Forecasting the Operation of a Gas Turbine Unit on Hydrogen Fuel ^†

Abstract

The development of hydrogen energy can significantly reduce the negative impact on the environment. For the successful implementation of hydrogen technologies, it is necessary to transform existing models of production, distribution, and consumption of both thermal and electrical energy. The processes of fuel conversion and combustion are complex and, in some cases, insufficiently studied. A complete replacement of natural gas with hydrogen requires an assessment of energy and environmental characteristics. This study aims to evaluate the operation of a gas turbine unit when transitioning to hydrogen fuel. The GE 6FA engine was chosen as the object of study. Mathematical modeling of this engine was conducted using the software complex “AS GRET” (Automated System for Gas Dynamic Calculations of Power Turbomachinery).

1. Introduction

Gas turbine installations are becoming a key type of energy equipment, both in the modernization of outdated thermal power plants and in the construction of new generating capacities. In accordance with the energy sector development strategy until 2042, the focus will be on creating gas turbine installations with capacities of 25, 65, and 170 MW.

Natural gas is the primary fuel for gas turbines. However, fuel preparation systems allow for the use of a wide range of both gaseous and liquid fuels, such as natural gas, liquefied gas, diesel fuel, distillates, kerosene, associated petroleum gas, biogas, and others. The properties of different types of fuel can vary significantly depending on their state, chemical composition, and the presence of impurities [1,2,3].

When burning fuel gas, certain requirements must be considered and adhered to, as violations can lead to equipment shutdown or even destruction of the combustion chamber.

Fuel stability against auto-ignition. In the process of preparing gaseous fuel for combustion, it is important to ensure its cleaning from foreign mechanical impurities, drying, and compression in booster compressors, while the fuel condition must remain stable.

Compliance with Environmental Requirements

To enhance the ecological safety of the installation, it is necessary to continuously monitor the content of NOx, CO, and CO₂ in the combustion products:

• Stability of the fuel gas against re-ignition;
• Stability of the fuel against micro-explosions;
• Stable dynamic pressure during combustion.

When designing a gas turbine installation, it is important to consider the fuel characteristics:

• Component composition;
• Heat of combustion;
• Nature and quantity of contaminants and composition of impurities.

Until the 1970s, gas turbine installations primarily used diffusion combustion chambers. However, with the tightening of emission requirements in exhaust gases, the design of these chambers became more complex. To reduce NOx emissions, modernization was carried out, including the addition of a steam injection system into the flow part [4,5]. It was important to minimize emissions under various operating modes, not just in the base mode, which led to the implementation of combustion chambers with pre-mixing of a “lean” fuel–air mixture. With the development of technologies and the tightening of environmental requirements to reduce emissions, new requirements and restrictions on the physical and chemical properties of the fuel used for its effective and safe combustion have emerged [6,7,8]. The demands for improving the operation of combustion chambers and the efficiency of turbines are constantly tightening within the framework of the development of gas turbine technologies.

2. Fuel Gas System

2.1. Preparation of Fuel for Combustion

Preparing fuel for combustion is a critically important process, but equally significant is the assessment of potential fuel before its use in the combustion chamber. For evaluating fuel intended for gas turbine installations, several key criteria can be highlighted:

• Heat of Combustion—this is the primary energy characteristic that indicates the amount of heat produced during the combustion of various fuels, including fuel gases. The heat of combustion can be measured experimentally using a calorimeter. The determination method involves the complete combustion of a specific mass of the test fuel sample in a calorimetric bomb in a compressed oxygen environment, measuring the amount of heat released during the combustion, where combustion occurs at constant pressure. Typically, in the calculations for gas turbine parameters, the lower heat of combustion is used, which does not account for the heat of condensation of the combustion products [9,10].
• Condensation of Hydrocarbons and Moisture—this is an important criterion in the preparation of fuel gas. This aspect must be strictly adhered to in order to avoid the ingression of moisture and other impurities into the fuel pipelines of the gas turbine installations.

Unwanted impurities in fuel gas can cause damage to fuel injectors and the combustion chamber. Accumulation of moisture should be avoided, as it can lead to the formation of gas hydrates. Figure 1 shows the dependence of hydrocarbon condensation conditions on the fuel pressure at the inlet to the combustion chamber. When burning hydrocarbon fuel, the point of hydrocarbon condensation can be reached, leading to the formation of the “first drop” of hydrocarbons [11,12,13]. This point will be the minimum allowable when burning fuel in the combustion chamber of a gas turbine unit. Often, water droplets form before hydrocarbon condensation occurs.

The amount of moisture in the fuel depends on pressure and temperature—the lower the temperature, the higher the likelihood of droplets appearing in the fuel supply line, which is why it is important to maintain a constant temperature of the fuel gas supply. The conditions for hydrocarbon condensation can be represented as follows:

T_cond (P_gas)= 0.00009 (P_gas)³ − 0.0005(P_gas)² + 0.0637P_gas + 2.9803-0.000004(P_gas)⁴,

(1)

where T_cond is the minimum allowable temperature at which condensation does not occur; P_gas is the gas pressure before the combustion chamber.

The conditions for moisture condensation can be described as follows:

T_gas(P_gas) = 0.00007(P_gas)⁴ + 0.0029(P_gas)³ + 0.0346(P_gas)² + 0.3918P_gas+5.4149,

(2)

where T_gas is the condensation requirement for moisture at the point of interest; P_gas is the gas pressure at the inlet to the gas turbine fuel system.

3.

The concentration of impurities in the air and fuel is also important. Impurities may also include moisture. The amount of impurities can be calculated using the following formula:

$${\mathit{W}}_{\mathit{a}\mathit{i}\mathit{r}}={\mathit{G}}_{\mathit{a}\mathit{i}\mathit{r}}\times {\mathit{W}}_{\mathit{a}\mathit{i}\mathit{r}}+{\mathit{G}}_{\mathit{f}\mathit{u}\mathit{e}\mathit{l}}\times {\mathit{W}}_{\mathit{f}\mathit{u}\mathit{e}\mathit{l}},$$

(3)

where G_air is the air flow rate, kg/s; W_air is the concentration of impurities in the air, kg/m³; G_fuel is the fuel flow rate, kg/s; W_fuel is the concentration of impurities in the fuel, kg/m³.

4.

Wobbe Index. Gas turbine installations can use various types of fuel gases that differ in calorific value. Each turbine can operate under specific conditions. Different fuel gases have different combustion heat values, which requires appropriate adjustments to the control and combustion systems. The Wobbe Index serves as an indicator of the interchangeability of fuel gases. For an ideal fuel gas, it can be calculated using the formula:

$$W_{н}={\displaystyle \frac{H_u}{\sqrt{\frac{{\mu }_{г}}{28.96}{T}_{г}}}},$$

(4)

where H_u is the lower heating value; μ_г is the molecular weight of the gas fuel; T_г is the temperature of the gas fuel.

2.2. Alternative Fuels for Combustion in Gas Turbines

In the last decade, alternative fuel gases have gained popularity. Alternative fuel gases have a high potential for use in isolated and remote areas, reducing environmental impact. There are many types of fuel used in gas turbine combustion chambers, depending on how they are obtained. These include natural gas, diesel fuel, aviation kerosene, biogas, hydrogen, and ammonia.

According to the requirements for gas turbines, backup fuel must be provided (when the main fuel is gaseous, a second supply point for gaseous fuel must be arranged, or a reserve of liquid fuel must be ensured). This means that switching between two types of fuel is possible depending on operational needs. However, in combustion chambers operating on natural gas, a DLN control system is used for consistently low NO_x emissions, so most manufacturers still use diffusion combustion when switching to liquid fuel. When transitioning to liquid fuel combustion, it is important to supply water to reduce NO_x emissions.

Currently, almost all gas turbine manufacturers use DLE emission reduction systems and DLN low NO_x emission systems. Further emission reductions are only possible by switching to alternative fuels or partially blending with the original natural gas.

2.3. Hydrogen Fuel for Gas Turbines

Hydrogen is rarely found in its free state; however, it can be found in various compounds, such as water, minerals, and natural gas. The high energy value of hydrogen, which is 120–140 MJ/kg, promotes its use in various industries, including energy, chemical and food industries, petrochemicals, and metallurgy. However, the share of hydrogen use in the energy sector remains low—less than 2%. The existing economic model does not allow hydrogen to compete with traditional fuels.

In addition to the energy and economic efficiency of production, an important factor is its minimal impact on the environment. There are many methods for producing hydrogen: it can be extracted from organic materials, fossil fuels, and biomass, as well as through thermochemical methods, and by using bacteria and algae. In thermal power plants, the main method of hydrogen production remains electrolysis, but transporting hydrogen fuel via pipelines is also possible.

Currently, several methods for producing hydrogen fuel can be identified as follows: steam reforming, coal gasification, and water electrolysis; these methods allow for the production of hydrogen in unlimited quantities. The main method for producing green hydrogen is electrolysis using renewable energy sources [14,15,16].

3. Mathematical Model of a Gas Turbine

The object of study is the General Electric 6FA gas turbine unit. The turbine’s power is 80 MW in the base mode. Since the technical description of the engine lacks all the characteristics of the turbine components, the task was set to develop a mathematical model of this gas turbine unit. The mathematical model of the General Electric 6FA gas turbine will be created in the certified software complex AC GRET. AS GRET (v.2.3) is a software developed by a team of authors led by Professor A.V. Titov [17].

The system of nonlinear equations for the GE 6FA energy gas turbine as part of a thermal electric power station will be written in the following form:

f₁ (G_air,K_p,T^*_g) = ⧍G_airk,
f₂ (G_air,K_p,T^*_g) = ⧍G_airt,
f₃ (G_air,K_p,T^*_g) = ⧍G_out,

(5)

where

G_air—air flow rate, kg/s;

K_p—compressor coefficient, characterizing compression in the compressor;

T^*_g—gas temperature at the gas turbine unit (GTU), K;

G_airk—air flow rate in the compressor, kg/s;

G_airt—air flow rate in the turbine, kg/s;

G_out—amount of air at the turbine outlet section, kg/s.

This system of equations can be solved using the modified Newton–Raphson method, known as the “poly-method,” for solving systems of nonlinear equations. To conduct the research, it is necessary to model not only the gas turbine unit (GTU) but also the fuel preparation system, considering hydrogen as the initial fuel. Based on the results of creating the mathematical model, an a priori model of the gas turbine engine was obtained, with deviations from the passport data depending on the operating mode. Figure 2 shows the variation in the exhaust gas flow rate when creating the mathematical model, taking into account the relative error.

In

Table 1. Relative errors.

Operating Mode of the Engine	N, kW	δv,%	δt, %	δog,%
	32,000	−0.02	8.9	−4
2	35,000	−1.9	8.8	−5
3	40,000	1.2	7.2	−3
4	45,000	2.2	5.5	−2.5
5	50,000	5.3	5.3	−1.3
6	55,000	5.5	5.5	−1
7	60,000	7.1	6.5	1
8	65,000	6.5	6.5	1.5
9	70,000	6.1	6.1	1.1
10	75,000	5.2	5.2	1.2
11	80,000	5	5.8	1.8

, the relative errors of the air flow rate δ_v, fuel flow rate δ_t, and exhaust gas flow rate δ_og are shown as percentages of the calculated parameters of the a priori values. The largest error in the air flow rate was δG_v = 7.1% at a power of N = 70,000 kW, for the fuel flow rate δG_t = 8.9% at N = 32,000 kW, and the maximum deviations in the exhaust gas flow rate were observed at N = 32,000 kW, where δG_og = −4%δGog = −4%. The minimum error values were recorded for the air flow rate at N = 32,000 kW with δG_v = −0.02%, for the fuel flow rate at N = 75,000kW with δG_t = 5.2%, and for the exhaust gases at N = 60,000 kW with δG_t = 1%.

Analyzing the results obtained from the calculations based on the apriori model and the passport data of the gas turbine engine (Table 1), it can be concluded that using this mathematical model for research presents difficulties, and its identification based on experimental data, is required to create an adequate mathematical model for further analysis.

To ensure that the calculation errors do not differ from the passport data and the parameters of the actual operating engine, it is necessary to conduct identification under variable operating modes of the installation. For this purpose, identification was carried out using the software complex AS GRET. As a result, the characteristics of the engine in both the base and variable operating modes were obtained.

Table 2. Operating characteristics of the exhaust gas flow rate for the GE 6FA turbine.

Operating Mode of the Engine	N, kW	Gog, kg/s (Manufacturer’s Data)	Gog, kg/s (Posterior Model)	δ,%
1	32,000	84.774	85.018	−0.28
2	35,000	89.915	90.249	−0.37
3	40,000	102.757	102.880	0.119
4	45,000	115.615	116.046	0.371
5	50,000	128.456	128.892	0.338
6	55,000	141.293	141.688	0.279
7	60,000	154.130	154.530	0.259
8	65,000	166.966	164.416	0.269
9	70,000	179.801	180.034	0.129
10	75,000	192.672	192.941	0.139
11	80,000	205.518	205.764	0.119

presents the operating characteristics of the exhaust gas flow rate.

The relative error of the mathematical model of the gas turbine installation after identification compared to the passport data of the GE 6FA gas turbine does not exceed 0.5%. An error of less than 1% is sufficient for conducting research on the mathematical model of the gas turbine engine.

Determining the enthalpy of fuel is a complex and critical stage in performing calculations of thermodynamic processes in the combustion of the fuel–air mixture. Theoretical calculation methods allow us to find only the difference in the enthalpies of the substance at a given temperature and at the initial temperature.

$${\mathrm{H}}_{\mathrm{Т}}-{\mathrm{H}}_{{\mathrm{Т}}_0}={\int }_{{\mathrm{Т}}_0}^{\mathrm{Т}}{\mathrm{C}}_{\mathrm{p}}\mathrm{ d}\mathrm{T}+\sum \mathsf{\Delta }{\mathrm{H}}^{\left(\mathrm{i}\right)}.$$

(6)

In thermodynamics, there is no need to determine absolute values of enthalpy. For thermodynamic calculations, it is only necessary to know the change in enthalpy, measured from an arbitrarily chosen reference point. The reference system can be any, but it must be the same for all substances involved in the process, for the fuel, and for the combustion products.

Any component participating in combustion can be obtained as a result of a chemical reaction from individual substances. Therefore, each type of substance corresponds to its own set of chemical elements. Individual substances in their most common, natural state are called elements in standard state. For example, O₂, H₂, F₂, Cl₂, N₂—in gaseous; C, Al, Mg, Li—in crystalline states.

Because of the modeling, a conditional formula for hydrogen fuel has been obtained for simulating the operation of the turbine (

Table 3. Conditional formula of fuel gas.

Fuel Gas	H	Enthalpy, kJ/kg
hydrogen	99.21619	−4650

).

The created mathematical model and methodology make it possible to predischarge in the main energy characteristics of a gas turbine installation. It is important to note that the simulation of a gas turbine installation is performed without changing the control system of the fuel treatment system, which makes it possible to evaluate changes in engine characteristics when changing the type of fuel gas. Figure 3 shows the change in hydrogen consumption under variable operating conditions of a gas turbine unit.

When the power changes, the consumption of hydrogen increases, but the consumption of exhaust gases remains constant, as the turbine can operate as part of a combined cycle power unit [18,19]. It is important to note that the modeling was conducted with a constant temperature in the combustion chamber, which is crucial for the materials and components of the turbine’s flow part.

4. Conclusions

The article emphasizes the importance of transitioning to hydrogen energy to reduce negative environmental impacts, which is a key factor in combating climate change. It demonstrates that existing gas turbine units, particularly the GE 6FA, can be adapted to run on hydrogen fuel, opening up opportunities for modernizing energy systems and improving their environmental efficiency. The developed mathematical model of the GE 6FA gas turbine, created using the AC GRET software suite, demonstrated high accuracy (deviations do not exceed 0.5%), confirming its suitability for research and optimization of the unit’s operation under various conditions. Special attention is given to fuel preparation, where parameters such as heat of combustion, hydrocarbon condensation conditions, and impurity concentration are crucial, as they significantly affect combustion stability and prevent damage to turbine components. Alternative fuel types, including hydrogen, are considered, enhancing the operational flexibility of gas turbine units and enabling adaptation to changing market conditions and emission requirements. The study highlights the need for further research to refine models and deepen the understanding of hydrogen combustion processes, as well as to develop control systems aimed at improving efficiency and reducing emissions. The obtained results are significant for energy policy, as the integration of hydrogen technologies into gas turbine units could be an effective step toward cleaner electricity generation, requiring government support and investments in scientific research and infrastructure. Thus, the transition to hydrogen fuel in gas turbine units represents a promising direction for improving energy efficiency and reducing environmental impact, provided the necessary technological and regulatory conditions are established.