Thermodynamic Analysis of Gas Turbine Systems Fueled by a CH₄/H₂ Mixture

Abstract

In the coming years, as a result of changing climate policies and finite fossil fuel resources, energy producers will be compelled to introduce new fuels with lower carbon footprints. One of the solutions is hydrogen, which can be burned or co-fired with methane in energy generation systems. Therefore, this study presents a thermodynamic and emission analysis of a gas turbine fueled by a mixture of CH₄ and H₂, as well as pure hydrogen. Numerical studies were conducted for the actual operating parameters of the LM6000 gas turbine in both simple and combined cycles. Aspen Hysys and Chemkin-Pro 2023R1 commercial software were used for the calculations. It was demonstrated that with a constant turbine inlet temperature set at 1723 K, the thermal efficiency increased from 39.4% to 40.2% for the gas turbine cycle and from 49% to 49.4% for the combined cycle gas turbine. Nitrogen oxides emissions were calculated using the reactor network, revealing that an increase in H₂ content above 20%vol. in the fuel leads to a significant rise in nitric oxides emissions. In the case of pure H₂, emissions are more than three times higher than for CH₄. The main reason for this increase in emissions was identified as the greater presence of H, O, and OH radicals in the reaction zone, causing an acceleration in the formation of nitric oxides.

1. Introduction

Due to increasing energy demand and stricter carbon dioxide reduction regulations, as highlighted by the UN Framework Convention on Climate Change [1], the imperative need to transition to clean energy has become evident. This transition must rapidly reduce greenhouse gas emissions to net zero over the coming decades to meet the goals of the 2015 Paris Agreement. More specifically, efforts should focus on limiting temperature increases to 1.5 °C above pre-industrial levels and keeping the global average temperature increase significantly below 2 °C. The energy sector’s ambitious goal of achieving net-zero CO₂ emissions necessitates compensating for emissions persisting from specific global regions or industries where abatement is technically challenging or not economically viable. This can be achieved through carbon minimization and storage in other energy-related areas [2]. Additionally, due to the discontinuous and fluctuating nature of renewable energy sources (RES), there is a compelling need for highly effective and dependable energy storage to offer continuous, on-demand energy around the clock. These challenges pose a significant hurdle for both the industry and research sectors, achievable only through a continuous mix of alternative fuels and breakthrough technologies. Clean alternative fuels like hydrogen and biofuels have been proposed as solutions to address these challenges, particularly in gas turbines (GT). Hydrogen, with an energy content of 120 MJ/kg on a mass basis—much higher than traditional fuels like natural gas (48 MJ/kg)—becomes more desirable in certain scenarios. It holds promise as an energy source that can be stored and converted back into electricity. During times of energy surplus, hydrogen can be generated and used as a fuel, further converted back to energy. Notably, hydrogen, burned in air to produce high-temperature water vapor, can be harnessed as a clean and environmentally beneficial fuel.

One potential application of H₂ in the power industry lies in its use in gas turbines, known for their highest thermal efficiencies. While the fundamentals of gas turbine cycles have been extensively studied for most simple cycle gas turbine modifications, only a few have effectively made it to commercial use [3,4,5,6] The gas turbine’s need for highly specialized and technologically advanced components presents a challenge compared to alternative systems performing similar functions. Gas turbines have been instrumental in power generation over the last three decades [7]. These heavy-duty gas turbines must deliver high power output, exhibit no weight issues, and maintain excellent efficiency to compete with alternative power generation systems like steam cycles. During this time, the significant development of combined heat and power (cogeneration) systems leveraged the gas turbine’s advantageous property of delivering substantial heat at high temperatures in the turbine exhaust without compromising performance [8]. The combined gas-steam cycle, utilizing emitted heat to generate power, represents a significant innovation in this field, referred to as the heavy-duty gas utilized by gas turbines. However, the most effective technology for large-scale power generation systems remains combined cycles [9]. The choice of fuel used in the combustion chamber significantly impacts the effectiveness of combustion and emissions in these processes. Presently, the primary fuels employed in these cycles are fossil fuels like oil and gas [10]. Despite the benefits and appeal of gas turbine systems (GTs) for electricity production, their drawback remains the release of greenhouse gases due to fossil fuel use. Reducing GHG emissions from GT combustion chambers can be achieved by burning pure “green hydrogen” (green hydrogen refers to hydrogen produced from the electrolysis of water with renewable electricity) or blending it with other fuels. However, operating gas turbines on hydrogen presents various challenges compared to natural gas. Firstly, careful design is necessary to ensure safe hydrogen combustion due to its maximum burning velocity, potentially seven times faster than that of natural gas. Secondly, the broader flammability limits and shorter ignition delay time of H₂ blends may lead to the flashback phenomenon. These factors can impose mechanical stress on the combustor’s components, causing flame instability and undesired pressure fluctuations [11]. Another crucial aspect is the emission of toxic compounds, especially nitrogen oxides. This is primarily due to the higher combustion temperature of H₂ and changes in flame size and shape, leading to increased heat release per unit volume. Research evaluating the impact of adding hydrogen to natural gas in a swirl-stabilized model combustor showed in lean, premixed experimental conditions that the addition of hydrogen can decrease NO_x emissions and expand the stability limit [12]. Moreover, it has been demonstrated that introducing pilot injection when adding hydrogen to natural gas can enhance the system’s capability to regulate emissions. Therkelsen et al. [13] demonstrated that adding hydrogen to natural gas in a gas turbine improves fuel-air mixing, leading to lower NO emissions. In another study by Reale et al. [14], blending methane-hydrogen in GTs was found to enhance the combustion process’s regularity through steam injection. According to Liu et al. [15], the effects of hydrogen-enriched methane-air were influenced by the hydrogen enrichment and equivalency ratio, both affecting the flame structure. Additionally, Yoshimura et al. [16] indicated that the interaction between hydrogen and natural gas can decrease NO_x emissions through the hydrogenation of natural gas. Ditaranto et al. [17] found that the influence of pure hydrogen significantly reduces nitrogen oxide emissions. In the gas turbine system, the use of nitrogen dilution of hydrogen could replace exhaust gas recirculation. Several studies indicate that converting low-NO_x gas turbine burners from methane to pure hydrogen can double or even triple NO_x emissions [18]. The high flame temperature characteristic of hydrogen combustion is well known. One of the primary chemical pathways contributing to the creation of NO_x involves a kinetic pathway where the nitrogen in the air is oxidized by oxygen at high temperatures. This mechanism, highly sensitive to temperature, is known as the thermal NO_x mechanism or Zeldovitch’s mechanism [19]. An association between stoichiometric flame temperature (SFT) and NO_x emissions for various fuels in typical gas turbine settings was documented by Todd and Battista in [20]. Their findings revealed that undiluted H₂ leads to unacceptable emission levels, necessitating a significant reduction in SFT to achieve emissions comparable to power industry standards. Similar observations have been reported when co-firing H₂ mixtures with other fuels, for instance, in reciprocating engines [21,22] and heating boilers [23,24]. As shown in the literature review, there are contradictions regarding the effect of H₂ content in fuel on nitrogen oxide emissions. This is related to the predominant pathways of NO_x formation in different combustion regimes and flame types. For example, nitric oxides emission decreases with increasing hydrogen share in laminar flames at a given combustion temperature, while for turbulent flames the trend is opposite. This necessitates the need for further in-depth study of NO_x formation mechanisms for the respective combustion regimes found in various energetic applications.

In addition to this, hydrogen, in comparison to natural gas, produces a lower mass flow rate and distinct product gases with higher water content, subsequently affecting the mixture’s molecular weight and specific heat. The fluctuation of enthalpy drop during expansion significantly impacts a gas turbine’s operation. Variations in the flow rate at the turbine’s inlet affect the compressor and turbine compatibility, while changes in the heat-transfer coefficient on the turbine blades’ exterior impact the effectiveness of the cooling system [25]. The study demonstrates that as the volumetric percentage of hydrogen increases, the radius of the maximum temperature zone decreases, yet the temperature peak and NO_x emissions rise. Notably, the combustion characteristics of the flame remain largely unchanged at low volumetric hydrogen percentages (less than 10%). It is illustrated that, although the addition of hydrogen leads to a reduction in flame length, a limited concentration of hydrogen causes an increased flame length (similar to that associated with pure methane). This occurs as low volumetric hydrogen concentrations result in a smaller mixing region on the lateral side [26].

This paper presents three gas turbine systems: simple cycle, combined cycle, and modified combined cycle, each of which allow the use of hydrogen as fuel. The calculations regarding the impact of hydrogen content in the fuel on efficiency and emissions were conducted using data from actual gas turbine power plants provided by GE Gas Power LM 6000, which is a novelty in contrast to previous work based on theoretical data. The sensitivity analysis considers the effect of H₂ on thermal efficiency, specific work, thermodynamic parameters of the cycle, and emissions.

2. Materials and Methods

2.1. Thermodynamic Analysis

The hydrogen power cycles underwent sensitivity analyses to examine how the proportion of hydrogen affects thermal efficiency, the temperature of the combustion chamber, and the available work in the power plant. The power outputs and turbine inlet temperature (TIT) are influenced by varying mass flow rates of fuel and air, consequently affecting the exhaust gas and its composition. This results in a different heat capacity of the exhaust gas.

The simulation solutions for oil and gas operations where thermodynamic cycle modeling was required were performed in the component-based program Aspen HYSYS. The program includes a component library where users can select and specify the attributes of components, including combustion chambers, turbines, pumps, compressors, etc. The Aspen HYSYS model was subsequently solved using a specific method. Finally, the simulation results of the model were compared to those of studies in order to assess its effectiveness. Energy balances are applied to program the components, and streams connect these components. The material composition of each stream can be selected from a component list, along with its attributes such as temperature, pressure, mass flow, etc. Aspen HYSYS has the capability to replicate both the steady-state and dynamic performance of complex chemical/hydrocarbon fluid-based processes by connecting various components through material and energy streams [27,28,29,30,31]. This enables the simulation of power plants and related energy options or systems. In Aspen HYSYS, all plant components must be solved sequentially rather than simultaneously. Aspen HYSYS encounters significant challenges due to the highly complex steam circuits involving mass and energy recycling in CCGT plants, necessitating simultaneous solutions. The Peng-Robinson fluid package was utilized for air, fuel, and exhaust gas, while the ASME steam table was employed for water and steam. The combustor was simulated using the Conversion Reactor module. Tailored to the project’s needs, certain library components have been created and integrated. For instance, the combustion chamber has been modified and programmed to facilitate the combustion of hydrogen, replacing natural gas or a CH₄/H₂ mixture. Fuel combustion was specified through a set of conversion reactions with 100% efficiency, and heat loss from the combustion chamber was assumed to be constant for all fuels under study. The mass of air supplied to the compressor was calculated based on the combustion reaction of the CH₄ and H₂ mixture (Equation (1)), considering the equivalence ratio. The choice of the equivalence ratio was determined through iterative processes to achieve a consistent turbine inlet temperature (TIT) of 1723 K for all tested fuels. For pure methane, the turbine’s isentropic efficiency was set to 0.86 to match the published flue gas temperature. An isentropic of compressor efficiency of 0.88 was selected to obtain a simple cycle efficiency of 36.4%, according to data presented in [32].

$$m_{air}=m_f· \frac{(2x_{{CH}_4}+0.5x_{H_2}){\rho }_{air}}{0.209\phi }$$

(1)

where x_CH4, and x_H2 denote the molar fraction of CH₄ and H₂ in the fuel, φ denotes the equivalence ratio, and ρ_air is air density in standard conditions. Mass flow rates of fuel were calculated with a constant input power Q_in = 50 MW, according to Formula (2).

$$m_f=\frac{Q_{in}}{(g_{{CH}_4}·{LHV}_{m,{CH}_4}+g_{H_2}·{LHV}_{m, H_2})}$$

(2)

where g_CH4 and g_H2 are mass fraction of fuel components and LHV_m is the low heating value.

Fuel characterizations are presented in

Table 1. Fuel characteristics.

H2 [% vol.]	CH4 [% vol.]	LHVm [MJ/kg]	LHVv [MJ/m3]	SFT [K]	A/F [-]
0	100	50.0	35.8	2224	17.1
20	80	52.2	30.8	2233	17.6
40	60	55.4	25.8	2247	18.4
60	40	61.1	20.8	2268	19.1
80	20	73.4	15.8	2304	22.8
100	0	120.0	10.8	2379	34.1

, while the most important initial parameters for studied cycles are listed in

Table 2. Cycle inputs and parameters inserted in Aspen HYSYS [33,34,35].

Parameter	Unit	Value
Ambient temperature	K	300
Ambient pressure	MPa	0.1
Compression ratio	-	28
Fuel inlet temperature	K	300
Fuel inlet pressure	MPa	3.0
Compressor isentropic efficiency	-	0.88
Turbine isentropic efficiency	-	0.86
Steam inlet temperature	K	803
Flue gas outlet temperature	K	503
Combustion chamber efficiency	-	0.99

.

Thermal efficiency for the GT, CCGT, and CCGTP plants was computed as follows:

$$\eta =\frac{W_{net}}{Q_{in}}$$

(3)

where the power outputs for GT cycle was calculated according to Formula (4) and for CCGT, CCGTP to Formula (5).

$$W_{net,GT}=W_t-W_c$$

(4)

$$W_{net,CCGT\left(CCGTP\right)}=W_t+W_{st}-W_c-W_p$$

(5)

The water pump was simulated by the Pump module in Aspen HYSYS and the power (W_p) required to drive it was determined for 95 bar and 378 K.

2.2. Toxic Compounds Emission Modelling

The combustion process of CH₄/H₂ fuel in a rich-quench-lean (RQL) combustor was modeled using ANSYS Chemkin-Pro 2023R1 software. The system, characterized by multi-stage combustion at various equivalence ratios, was represented by a chemical reactor network (CRN), as illustrated in Figure 1 [36]. The mass of recirculated exhaust gas was determined based on findings from Valera-Medina [37] and Mashruk [38], amounting to 30% of the mass. Subsequently, the recirculated exhaust gas stream was divided into two parts: 30% of the exhaust mass was fed to the mixing zone and the remaining part to the flame zone. The outlet from the flame zone was supplied to the plug flow reactor (PFR) to simulate reactions in the post-flame zone. The quenching/mixing zone was modeled using a partially stirred reactor (PaSR) and the lean-burning zone was modeled using another PFR.

The reaction mechanism GRI-Mech 3.0 0 was relied upon to predict chemical species formation, especially nitric oxides (NO, NO₂, and N₂O), for investigated fuels. Simulations were performed for six fuels: pure methane, pure hydrogen, and four CH₄/H₂ mixtures (Table 1). The other parameters for the calculations were adopted according to the data obtained during the gas turbine cycle calculations in Aspen HYSYS as well as on the basis of other previous research works (

Table 3. Boundary conditions for the toxic compound emission modeling process.

Parameter	Symbol	Unit	Value
Mixing zone
Pressure	P0	MPa	28.3
Temperature	T	K	823
Residence time in premixing zone	τp	s	0.0005
Recirculation zone
Pressure	P0	MPa	28.3
Temperature in recirculation zone	TR	K	1600
Residence time in recirculation zone	τR	s	0.0015
Fraction of recirculating mass	mrec	wt.%	30
Flame zone
Pressure	P	MPa	28.3
Temperature	TF	K	1600
Residence time in flame zone	τF	s	0.0011–0.0015
Equivalence ratio in flame zone	φF	-	1.8
Post-flame zone
Pressure	P	MPa	28.3
Starting axial position	x0	cm	0
Ending axial position	x1	cm	5
Quenching zone
Pressure	P	MPa	28.3
Temperature	TQ	K	1600
Residence time in quenching zone	τQ	s	0.0012
Secondary air temperature	Ts	K	823
Lean-burn zone
Pressure	P	MPa	28.3
Starting axial position	x0	cm	0
Ending axial position	x1	cm	5
Equivalence ratio in lean-burn zone	φLB	-	0.36–0.4

).

Different hydrogen properties such as increased diffusivity and SFT resulted in changing some boundary conditions. For example, in the calculations, the residence time of reactants in the flame zone was reduced, and the amount of air supplied to the lean-burn zone was increased to maintain the published temperature.

3. Results and Discussion

3.1. Gas Turbine Operation Analysis

All cycles are modeled under the assumption that air can be freely supplied, and hydrogen is delivered as pressurized fuel from high-temperature electrolysis. For the thermodynamic analysis of gas turbine cycles, three CH₄/H₂ fuels were chosen, containing 20%, 40%, and 50% vol. of H₂. Additionally, pure methane and hydrogen were used as supplementary fuels. The gas turbine consists of an air compressor (C) and a turbine (T) operating on a common shaft, with a combustor (CC) situated in between. The model incorporates direct combustion, where fuels react with compressed air at 823 K and 2.83 MPa in the combustion chamber, undergoing a constant-pressure process to produce gases at the required temperature TIT = 1723 K. The TIT is achieved at an equivalence air ratio of 0.4 for CH₄/H₂ mixture and 0.36 for 100% hydrogen fuel. The adopted model assumes no air mass loss between the compressor and the combustion chamber.

3.1.1. Simple Gas Turbine System

Figure 2 presents a simplified schematic picture of the modeled gas turbine cycle, with the thermodynamic parameters detailed in

Table 4. GT cycle characteristic parameters vs. fuel composition.

H2 [% vol.]	CH4 [% vol.]	T5 (TOT) [K]	WC [MW]	WT [MW]	A/Q [kg/MJ]	Cp [kJ/kgK]	Adiabatic Index
0	100	928	23.7	43.4	0.860	1.328	1.253
20	80	936	23.0	42.8	0.847	1.332	1.252
40	60	935	23.1	42.9	0.832	1.338	1.252
50	50	934	22.8	42.7	0.826	1.342	1.251
100	0	932	22.4	42.5	0.798	1.382	1.248

. Under the assumption of a constant compression ratio, initial parameters for air and fuel, and a constant turbine inlet temperature (TIT), the variable parameters in the cycle include the exhaust gas temperature, as well as the operation of the compressor and turbine.

As the proportion of H₂ in the fuel increases, the work required for air compression decreases. This is attributed to the lower specific air demand for energy delivered with hydrogen fuels. Conversely, the turbine power (W_T) shows a downward trend with increasing H₂ content in the fuel, influenced by decrease of mass flue gases passing through the turbine. This effect is diminished by an increase in the heat capacity of the flue gas resulting from an increase in the share of water vapor. Consequently, a higher energy value available for the turbine per unit mass and temperature difference is achieved. Based on the above observations, the highest thermal efficiency, calculated using Equation (3), was achieved with pure hydrogen at 40.2%, surpassing the pure methane-fueled cycle by 0.8%. The thermal efficiency and W_net values for the analyzed fuels are illustrated in Figure 3.

3.1.2. Combined Cycle Gas Turbine CCGT

Given that the temperature of the flue gas exiting the gas turbine is approximately 930 K, there is an additional opportunity to enhance the primary energy utilization by implementing a wet cycle. The conducted analysis evaluated the impact of the fuel composition supplied to the upper cycle on the thermodynamic parameters of the combined cycle gas turbine system. The studies were conducted for two systems: the conventional combined cycle gas turbine (CCGT) system (Figure 4) and the CCGT system with additional heat recovery, denoted as CCGTP (Figure 5).

The exhaust gas from the gas turbine then passes through the heat recovery steam boiler (HE) before being released into the environment as flue gas. The HE extracts the remaining heat from the exhaust gas to produce steam. The CCGTP model incorporates an additional HE2 exchanger, which reheats the water using the energy received from the steam exiting the steam turbine. For the analyses of both CCGT and CCGTP, the recovery boiler was assumed to produce steam at a pressure of 9.5 MPa and a temperature of 803 K. The HE was supplied with water at 9.5 MPa and 378 K. The flue gas temperature (T9 in Figure 4 and Figure 5) leaving the boiler was kept constant for all investigated fuels at 503 K. The heat transfer process occurred without pressure losses, and a device efficiency of 100% was assumed to maximize the power generated from the system.

The heat generated in the heat recovery steam generator is influenced by key thermodynamic parameters of the flue gas, including temperature, specific heat, and the mass of the flue gas. Altering the fuel composition consequently impacts the available energy. An increase in the proportion of hydrogen in the fuel leads to a higher amount of water vapor in the flue gases, reducing the share of carbon dioxide. At the same temperature of the exhaust gas (TOT), this elevation in water vapor content raises its enthalpy, approximately by 3.2 for pure H₂. However, the combustion of pure hydrogen results in a reduction in the mass flux of flue gas flowing through the HRSG (a reduction of about 9% for pure H₂), which reduces the amount of steam produced with the required parameters. This leads to a decrease in the generated power on the steam turbine for pure H₂ by approximately 3% compared to CH₄ as a fuel. The incorporation of an additional recuperative heat exchanger in the CCGTP system results in an increase in power generated on the steam turbine by 0.46 MW for CH₄ and 0.41 MW for pure H₂. The results of the calculated steam turbine power and cycle power output for the CCGT and CCGTP systems are presented in

Table 5. CCGT and CCGTP cycles’ characteristic parameters vs. fuel composition.

H2 [% vol.]	CH4 [% vol.]	CCGT		CCGTP
		WST [MW]	Wnet [MW]	WST [MW]	Wnet [MW]
0	100	4.34	24.04	4.80	24.50
20	80	4.35	24.10	4.82	24.57
40	60	4.34	24.18	4.80	24.64
50	50	4.33	24.23	4.79	24.69
100	0	4.21	24.30	4.62	24.72

, while Figure 6 illustrates the impact of fuel composition on the efficiency of the CCGT and CCGTP systems.

Analyzing the data presented in Figure 6, it is evident that the impact of H₂ on the efficiency of the CCGT and CCGTP system is less pronounced than in the case of the simple system. Despite this, an improvement in efficiency is still achieved with an increase in H₂ content. This improvement is linked to the greater power generated in the gaseous part of the cycle. However, in the wet part of the cycle, higher power generation values are obtained for hydrocarbon fuels.

Incorporating hydrogen into gas turbine systems (GT and CCGT) additionally contributes to the reduction of greenhouse gas emissions. For the systems studied, substituting methane with hydrogen could result in a reduction of CO₂ emissions by over 86 million tons per year.

3.2. Numerical Results from the Chemical Reaction Network

One crucial parameter during fuel combustion, including hydrogen fuels, is the emission of toxic compounds, particularly nitrogen oxides (NO_x). Their contribution to the overall emission is influenced by factors such as process temperature, oxygen quantity, and the presence of radicals. This subsection presents the results of numerical calculations for NO_x emissions during the combustion of CH₄/H₂ mixtures in the rich-quench-lean (RQL) combustor, using input parameters similar to those in previous analyses. Figure 7 depicts the results of temperature distribution in the RQL combustor for the investigated fuels.

Temperature of the flame increases significantly at the flame zone, where the effect of the hydrogen content in the fuel is the most visible. The value of the maximum temperature increases with increasing H₂ and reaches values of 2587 K for pure hydrogen. For fuels with significant H₂ content, a further temperature increase of several degrees is noticeable in the post-flame zone. Temperature is then reduced to the required turbine entry temperature via mixing with significantly cooler secondary air at the quenching zone. The further temperature rise in the lean-burn zone is due to the oxidation of combustible compounds contained in the flue gas, such as unburned hydrocarbons and carbon monoxide. The molar fractions of selected chemical compounds are summarized in

Table 6. Molar fractions of O₂ and CO in RQL combustor.

H2 Content in Fuel [% vol.]	Flame Zone		Post-Flame Zone		Quenching Zone		Lean-Burn Zone
	O2 [%]	CO [%]	O2 [%]	CO [%]	O2 [%]	CO [%]	O2 [%]	CO [ppm]
0	0.03	9.45	0	10.01	13.11	2.66	11.33	2.9
20	0.02	8.99	0	9.38	13.01	2.09	11.29	2.0
40	0.02	8.26	0	8.49	13.14	1.92	11.21	2.0
60	0.01	7.04	0	7.14	13.07	1.73	11.19	1.8
80	0.01	4.80	0	4.83	13.14	1.07	11.31	1.2
100	0.00	0	0	0	13.26	0	11.51	0

and

Table 7. Molar fraction of NO and NO in RQL combustor (data presented in ppm).

H2 Content in Fuel [% vol.]	Flame Zone		Post-Flame Zone		Quenching Zone		Lean-Burn Zone
	NO	NO2	NO	NO2	NO	NO2	NO	NO2
0	36.0	0.0	42.2	0.0	135.8	2.2	150.6	1.7
20	43.6	0.0	43.4	0.0	157.4	3.7	169.2	2.0
40	54.7	0.0	43.6	0.0	177.4	4.1	210.6	2.5
60	69.8	0.0	43.6	0.0	210.9	2.9	281.0	2.8
80	85.4	0.0	54.5	0.0	385.4	5.6	395.4	4.5
100	127.7	0.0	131.1	0.0	483.4	7.5	495.4	5.6

.

Analysis of the data shows that the effect of hydrogen in the fuel on NO formation occurs in every zone of the combustion chamber. In the highest-temperature area (the flame zone and post-flame zone), increasing the share of H₂ raises the amount of NO, even despite the absence of oxygen (φ = 1.8). The largest increase in nitrogen oxides (tripling the value) is recorded in the quenching zone. This area is characterized by the lowest temperature but with the highest proportion of oxygen and free radicals (OH, O, and H). The amount of O, H, and OH radicals in the quenching zone rises with the increase in the molar percentage of H₂ in the fuel and is, respectively, six times higher for H and 3.5 times higher for O and OH radicals when burning pure hydrogen. This zone produces a negligible amount of nitrogen dioxide, which is partially reduced in the lean-burn zone. The relative distribution of the free radical content (H, O, and OH) in specific zones of the RQL combustor with respect to the H₂ content in the fuel is shown in Figure 8. A value of 1 indicates the highest concentration of radicals in the investigated zones. The largest increase in the proportion of O, H, and OH free radicals is noticeable for fuel hydrogen content above 60% vol. in three of the analyzed RQL zones. This results in an intensification of the formation of nitrogen oxides, especially in the quenching zone (an 83% increase in emissions after increasing the share of H₂ from 60 to 80%). The reaction pathway of nitric oxide formation in the quenching zone is presented in Figure 9. In the lean-burn zone, the amount of radicals is at a similar level regardless of fuel composition.

Sensitivity analysis of formation mechanism of nitrogen oxides in the quenching zone (PaSR reactor) showed that for all fuels analyzed, the main reaction is that of HNO + H ↔ H₂ + NO. Increasing the share of hydrogen in the fuel to 100% vol. results in an increase in net reaction rate by several times compared to methane, mainly through increased supply of H radicals. In addition, the increased availability of oxygen and O and HO radicals in the quenching zone also affects minor reactions of NO formation, such as HNO + O ↔ NO + OH, HNO + O₂ ↔ HO₂ + NO and HNO + OH ↔ NO + H₂O. The further increase in NO emissions formed in the lean-burn zone reactor is based on the oxidation reaction of nitrogen N through OH radicals (N + OH ↔ NO + H) and O₂ (N + O₂ ↔ NO + O). For fuels with 80 and 100% vol. H₂ content, the amine radical oxidation reaction also contributes to the increase in NO production (NH + O ↔ NO + H and NH + O₂ ↔ NO + OH).

Final normalized NO_x emissions (which have been normalized to 15% oxygen in accordance with gas turbine standards) are presented in Figure 10.

The final emissions values obtained exceed the permissible limits under the legislation [39]. However, they clearly show the effect of hydrogen on NO_x formation. Any addition of H₂ to the fuel raises the final NO_x emissions, which must be taken into account when modifying combustion systems in gas turbines in the decarbonization of electricity production by introducing green hydrogen.

4. Conclusions

In the present work, numerical investigation has been carried out to examine the effects of hydrogen addition to methane fuel on gas turbine operation parameters like efficiency, work output, and toxic compound emissions. The following is concluded:

• Substitution of hydrocarbon fuels with hydrogen contributed to increased efficiency and generated power in both GT and CCGT thermodynamic cycles. The main reason is an increase in the enthalpy of the flue gas due to an increase in the share of water vapor in the flue gas. This allows efficiency gains of 0.8% and 0.53% for the TG and CCGT systems, respectively. The lower growth for the combined system is due to lower power output of the steam turbine as a result of the reduction of the exhaust gas mass flux by about 9% when changing the fuel from CH₄ to H₂.
• The results indicate that the addition of H₂ increases NO and NO₂ emission. Emissions more than three times higher were recorded for pure hydrogen than for methane. The significant increase of NO_x formation was the result of the reactions taking place in the in quenching zone, where the highest values of free radicals (O, H, and OH) were obtained. Increasing the share of H₂ in the fuel raises the amount of radicals, resulting in a growth in the net reaction rate for NO_x formation by several times compared to methane fuels.

The results of this work show that hydrogen fuels can be effectively used in gas turbine systems; however, further research is needed to reduce the higher emissions of nitric oxides.