Integrated Gasification Combined Cycle Power Plant Research Articles

CO2-selective membrane reactor process for water-gas-shift reaction with CO2 capture in a coal-based IGCC power plant

Integrated gasification combined cycle (IGCC) power plants enable pre-combustion carbon capture to reduce CO2 emissions. Membrane water-gas-shift (WGS) reactors can intensify these processes by converting raw syngas to H2 with simultaneous CO2 capture in one unit. This paper reports process design and techno-economic analysis (TEA) for a membrane reactor (MR) process with a CO2 selective ceramic-carbonate dual-phase (CCDP) membrane for WGS reaction with CO2 capture for a IGCC power plant. The target performance includes CO conversion > 95 %, hydrogen purity > 90 %, CO2 purity > 95 %, and carbon capture > 90 %. Using a commercial catalyst and a CCDP membrane, the MR can achieve the performance target at 750 °C and space velocity of 250 h−1. The outcome of the process design and TEA shows that the CCDP MR has an operating cost of $24 M/year, significantly lower than that for the conventional processes (40 M$/year). However, the MR process has a higher capital cost ($1007 M) than the conventional process ($527 M) because of the higher cost of the CCDP MRs. Modeling analysis shows a MR with higher CO2 permeance can deliver the target at a higher space velocity and lower membrane surface area to catalyst volume ratio, leading to a significantly reduced MR capital costs.

Analyses of hot/warm CO2 removal processes for IGCC power plants

Compared with a pulverized coal power plant, the integrated gasification combined cycle (IGCC) has several advantages, including, among others better environmental performance and low CO2 capture cost. Hot/warm CO2 removal from syngas has also been a subject of research due to its potentially higher thermal efficiency. In this study, we proposed a generic adsorption based hot/warm CO2 removal process for IGCC power plants. Through analyses of the proposed generic process we have demonstrated that higher temperature of the hot/warm CO2 removal process will results in larger heat of adsorption, which in turns may increase energy consumption of the process. Under most of the operating temperature range, hot/warm CO2 removal process will lead to more electricity loss compared to the baseline Selexol process. However, if the adsorption step takes place at a temperature close to or higher than the highest steam temperature in steam cycle, our analysis indicates that the process may lead to minimal electricity loss. The study also provided some other insights into the pathways for hot/warm CO2 removal process to improve its energy performance through process and sorbent designs.Graphical

Fuel calorific value control process analysis and research based on IGCC power plant

AbstractThe stability of the equipment has been more and more important with the continuous development of IGCC (Integrated Gasification Combined Cycle) technology. The control of the calorific value of the fuel gas of the gas turbine is one of the most important factors for the stable operation of the gas turbine. There are many variables in the calorific value of IGCC fuels that will cause unstable fuel combustion conditions and low thermal efficiency. In terms of process equipment, process conditions, instrument control calculation, and logic adjustment, this paper studies the automatic adjustment system of the calorific value of syngas for IGCC gas turbine fuel. The calorific value of the syngas can be automatically adjusted under different working conditions of the gas turbine. It helps the stable combustion of the gas turbine to form a perfect, efficient, reliable calorific value control system.

Process modelling and optimization of a 250 MW IGCC system: ASU optimization and thermodynamic analysis

Integrated gasification combined cycle (IGCC) underpins the advancement of pulverized coal combustion, yet the optimization of the air separation unit (ASU) in the IGCC system is still lacking, resulting in the limited reduction of energy consumption and efficiency improvement. Accordingly, a full-process IGCC model developed in our previous work (Energy, 2023,272: 127,040) is employed to optimize the ASU in a 250 MW IGCC power plant at an industrial scale. The feasibility of the ASU optimization was verified, and thermodynamic analysis evaluated the optimized IGCC system efficiency. The results show that the partial integration of ASU significantly reduces the compressor's energy consumption while the nitrogen re-injection method minimizes the use of saturated steam. Furthermore, reducing oxygen purity decreases the minimum separation work of the system. After optimization, the ASU uses only 53% as much power as the traditional system, and the total energy efficiency (44.9%) and exergy efficiency (43.6%) are improved by 2.2% and 1.8%, respectively. Consequently, the total energy consumption and exergy consumption decrease by 10.8% and 35.9%, respectively. The present work provides a comprehensive framework for optimizing other components of the IGCC system, which is expected to further reduce energy consumption and improve the system's efficiency.

A Methodological Sustainability Assessment to Process Intensification (MSAtoPI) by reactive-separation systems

To produce clean and cheap power by eliminating the economic and energy penalties, it is necessary to develop new technologies or improve the existing processes based on sustainability criteria and alternative fuels. Integration of sustainability into process design contributes to the achievement of this target by eliminating or minimizing negative effects. However, measuring sustainability performance and decision-making are crucial and challenging steps for the development of sustainable industrial processes. The framework for Methodological Sustainability Assessment to Process Intensification (MSAtoPI) is thus introduced in this study as a methodological approach with appropriate sustainability indicators that ensures the capability of gathering and abstracting the complex process operations (energy, mass, and momentum transport phenomena), and that offers clear analysis and communication. The main concepts are demonstrated in practice by using a biomass-based, highly efficient, and ultra-compact process to produce H2 while simultaneously capturing CO2 in an IGCC (Integrated Gasification Combined Cycle) power plant, which is intensified by reactive-separation systems (a hybrid membrane reactor (MR)/adsorptive reactor (AR) system). MSAtoPI clearly concretizes that the proposed intensified reactive-separation systems have huge potential to produce clean and cheap power by eliminating the economic and energy penalties by having more sustainable natures (minimum: ∼18%, average: ∼75%, maximum: ∼140% improvement in sustainability).

Thermal Design of a Biohydrogen Production System Driven by Integrated Gasification Combined Cycle Waste Heat Using Dynamic Simulation

Utilizing biological processes for hydrogen production via gasification is a promising alternative method to coal gasification. The present study proposes a dynamic simulation model that uses a one-dimensional heat-transfer analysis method to simulate a biohydrogen production system. The proposed model is based on an existing experimental design setup. It is used to simulate a biohydrogen production system driven by the waste heat from an integrated gasification combined cycle (IGCC) power plant equipped with carbon capture and storage technologies. The data from the simulated results are compared with the experimental measurement data to validate the developed model’s reliability. The results show good agreement between the experimental data and the developed model. The relative root-mean-square error for the heat storage, feed-mixing, and bioreactor tanks is 1.26%, 3.59%, and 1.78%, respectively. After the developed model’s reliability is confirmed, it is used to simulate and optimize the biohydrogen production system inside the IGCC power plant. The bioreactor tank’s time constant can be improved when reducing the operating volume of the feed-mixing tank by the scale factors of 0.75 and 0.50, leading to a 15.76% and 31.54% faster time constant, respectively, when compared with the existing design.

Optimization of Integrated Gasification Combined-Cycle Power Plant for Polygeneration of Power and Chemicals

Efficient and flexible operation is essential for competitiveness in the energy market. However, the CO2 emissions of conventional power plants have become an increasingly significant environmental dilemma. In this study, the optimization of a steam power process of an IGCC was carried out, which improved the overall performance of the plant. CCPP with a subcritical HRSG was modelled using EBSILON Professional. The numerical results of the model were validated by measurements for three different load cases (100, 80, and 60%). The results are in agreement with the measured data, with deviations of less than 5% for each case. Based on the model validation, the model was modified for the use of syngas as feed and the integration of heat into an IGCC process. The integration was optimized with respect to the performance of the CCPP by varying the extraction points, adjusting the steam parameters of the extractions and modifying the steam cycle. For the 100% load case, a steam turbine power achieved increase of +34.2%. Finally, the optimized model was subjected to a sensitivity analysis to investigate the effects of varying the extraction mass flows on the output.

Comparative environmental benefits of power generation from underground and surface coal gasification with carbon capture and storage

Underground gasification combined cycle (UGCC), when combined with carbon capture and storage (CCS), is widely judged to be a promising approach for clean coal utilization especially in the context of carbon neutral energy pathways. Nevertheless, the overall operation processes may consume a multiple of energy and inevitably trigger environmental concerns. Hence, a careful evaluation of the potential environmental impacts associated with UGCC is needed. In this study, we assessed environmental impacts of UGCC with and without CCS by the life cycle assessment method, and compared the results with those of surface integrated gasification combined cycle (IGCC) to gain better insight into tradeoffs of two coal gasification technologies and lighten the environmental burden by design optimizations. The results demonstrated that most mid-point impact values of UGCC power plants, which reflect pollution emissions and corresponding damage degree, were lower. Inversely, the global warming potential was 16.9% higher than those of IGCC power plants. Furthermore, UGCC power plants have superior end-point environmental benefits, which represent the damage of ecosystem quality, human health and resources. As demonstrated by the fact that the value of above three impact types were 23%, 15% and 4%, lower than those of IGCC power plants, respectively. In addition, the implement of CCS in two types of power plants decreased human health damage due to reduced greenhouse gas emissions, but notable environmental trade-offs are the increase in ecosystem quality damage and resource damage. The aggregated results show that UGCC with or without CCS has a more outstanding environmental performance with exception of global warming potential than IGCC with or without CCS. Enhancing UCG process control, improving syngas heating value and decreasing the energy in gasification agent preparation are effective methods to further reduce the GHG emissions. Approached in an improved way, UGCC-CCS stands to provide a low-carbon and self-contained solution for power production and energy provision.

Cost-benefit comparison of carbon capture, utilization, and storage retrofitted to different thermal power plants in China based on real options approach

A trinomial tree model based on a real options approach was developed to evaluate the investment decisions on carbon capture, utilization, and storage (CCUS) retrofitted to the three main types of thermal power plants in China under the same power generation and CO2 emissions levels. The plant types included pulverized coal (PC), integrated gasification combined cycle (IGCC), and natural gas combined cycle (NGCC) plants. We take into account a subsidy policy consistent with the 45Q tax credit of the U.S., as well as uncertainty factors, such as carbon price, technological progress, CO2 geological storage paths, oil price, and electricity price. The results showed that the investment benefit of ordinary NGCC power plants is 93.04 million USD. This provides greater economic advantages than the other two plant types as their investment benefit is negative if the captured CO2 was used for enhanced water recovery (EWR), even if 45Q subsidies are provided. Compared with NGCC + CCUS power plants, PC + CCUS and IGCC + CCUS power plants have more advantages in terms of economic benefits and emission reduction. The 45Q subsidy policy reduced the critical carbon price, which determines the decision to invest or not, by 30.14 USD t−1 for the PC and IGCC power plants and by 15.24 USD t−1 for the NGCC power plants. Nevertheless, only when the subsidy reaches at least 71.84 USD t−1 and the period limit is canceled can all three types of power plants be motivated to invest in CCUS and used the capture CO2 for EWR. Overall, the government should focus on the application of CCUS in coal-fired power plants (in addition to developing gas power generation), especially when CO2 is used for enhanced oil recovery (EOR). The government could introduce fiscal policies, such as 45Q or stronger, to stimulate CCUS technology development in China.

Modelling of Coal-Biomass Blends Gasification and Power Plant Revamp Alternatives in Egypt’s Natural Gas Sector

Recently, there has been a growing research interest in the co-gasification of biomass with coal to produce syngas and electricity in a sustainable manner. Co-gasification technology do not only decrease potentially the exploitation of a significant amount of conventional coal resources, and thus lower greenhouse gases (GHG) emissions, but also boost the overall gasification process efficiency. In the present work, a rigorous simulation model of an entrained flow gasifier is developed using the Aspen Plus® software environment. The proposed simulation model is tested for an American coal and the model validation is performed in good agreement with practical data. The feedstocks used in the proposed gasifier model are dry Egyptian coal and a blend of an Egyptian coal and rice straw that is gathered locally. The proposed gasifier model mainly consists of three reactors. The first one is a yield reactor where the coal pyrolysis occurs, the second reactor is a stoichiometric reactor where the gasification reactions arise, and the third reactor is a Gibbs reactor where the water-gas and steam-methane reforming reactions take place. The influence of using a feed mixture of 90 % coal and 10 % rice straw on the gasifier efficiency is investigated. The developed model provides a robust basis for revamping of an existing Egyptian natural gas-based power plant to replace its standard fuel with a coal-rice straw blend, in case of low natural gas supply. The model is further employed to assess different revamping scenarios and alternatives within the natural gas power plant. For a dry blend of (90 % Egyptian coal and 10 % rice straw), the cold gas efficiency is estimated as 85.7 %, while for dry Egyptian it is calculated as 79.61 %. The revamped Egyptian natural gas power plant decreases the total annualized cost (TAC) by 52.7 % with respect to a new constructed integrated gasification combined cycle (IGCC) plant. Besides, the payback period decreases to 1.24 y rather than 12 y in case of the construction of a new IGCC power plant. (Less)

Prospect of near-zero-emission IGCC power plants to decarbonize coal-fired power generation in China: Implications from the GreenGen project

An integrated gasification combined cycle (IGCC) power plant with pre-combustion CO2 capture provides a solution to achieve energy security with CO2 emission reduction in China, which has a coal-dominant energy resource structure. This study utilizes the electricity generation and cost information of the GreenGen IGCC plant (265 MW), which is the first and, to date, the only IGCC facility in China, to evaluate the economic performance and competitiveness of this emerging clean coal technology. In the construction stage, the initial investment on the GreenGen plant was approximately $565 million (capital cost: 2133 $/kW; in constant 2017 US dollars). Compared with the US, China incurred significantly lower costs of initial investment for the construction of the IGCC plant, owing to the adoption of a self-developed gasifier. During the operation stage, the levelized cost of electricity (LCOE) without CO2 capture for the GreenGen plant was calculated as 103 $/MWh, whereas it increased to 131 $/MWh with pre-combustion CO2 capture (CO2 capture cost: 42 $/tonne). Currently, an IGCC plant with integrated CO2 capture remains too expensive to be widely used in China. However, simulation results indicate that the LCOE of China’s IGCC plants could be potentially reduced to 80 $/MWh in the future owing to technology innovation, large-scale application and cumulative production. Government policy and financial support to stimulate the research and development of gas turbine and low-rank coal gasification technologies and to subsidize the operation of IGCC plants owing to their environmental benefits would play critical roles in accelerating the development of near-zero-emission IGCC power plants in China.

Syngas Compositions, Cold Gas and Carbon Conversion Efficiencies for Different Coal Gasification Processes and all Coal Ranks

Gasifiers in an Integrated Gasification Combined Cycle power plant (IGCC) are the heart of the system since they are the producers...

Performance evaluation of air-blown IGCC polygeneration plants using chemical looping hydrogen generation and methanol synthesis loop

Three chemical processing units by the integrated intermittent chemical-looping air separation (IICLAS), the chemical-looping hydrogen generation (CLHG), and the methanol synthesis loop (MSL) are integrated to retrofit the integrated gasification combined cycle (IGCC) system configuration. Four designs are presented and their performances are evaluated according to net efficiency, energy storage ratio (ESR), water saving ratio (WSR), and carbon emission rate (CER). An oxy-fuel IGCC power plant using IICLAS (Design 1) achieves 45.19% of net (thermal) efficiency. An oxygen-blown IGCC polygeneration plant with an integration of IICLAS and CLHG (Design 2) produces electricity and pure hydrogen simultaneously, and its net efficiency is up to 54.04%. An air-blown IGCC polygeneration (power/H2) plant without Brayton cycle and IICLAS (Design 3) ensures its net efficiency with 59.43%. An air-blown IGCC polygeneration plant with an integration of CLHG and MSL (Design 4) produces electricity, hydrogen, and methanol simultaneously, and its net efficiency could be as high as 60.42%. In addition, it is verified that Design 4 not only ensures the higher ESR due to hydrogen and methanol as storable fuels, but also it has an inherently lower environmental impact due to the lower CER, the higher WSR, and very low NOx emissions.

Integrated Process Design and Control for Smart Grid Coordinated IGCC Power Plants Using Economic Linear Optimal Control

The Integrated Gasification Combined Cycle (IGCC) possesses a number of advantages over traditional power generation plants, including increased efficiency, flex-fuel, and carbon capture. A lesser-known advantage of the IGCC system is the ability to coordinate with the smart grid. The idea is that process modifications can enable dispatch capabilities in the sense of shifting power production away from periods of low electricity price to periods of high price and thus generate greater revenue. The work begins with a demonstration of Economic Model Predictive Control (EMPC) as a strategy to determine the dispatch policy by directly pursuing the objective of maximizing plant revenue. However, the numeric nature of EMPC creates an inherent limitation when it comes to process design. Thus, Economic Linear Optimal Control (ELOC) is proposed as a surrogate for EMPC in the formulation of the integrated design and control problem for IGCC power plants with smart grid coordination.

The oxygen production pre-combustion (OPPC) IGCC plant for efficient power production with CO2 capture

This work presents a novel integrated gasification combined cycle (IGCC) power plant configuration for CO2 capture with minimal energy penalty. The proposed oxygen production pre-combustion (OPPC) power plant synergistically integrates a gas switching oxygen production (GSOP) unit into a pre-combustion IGCC power plant, reducing the energy penalty through two channels: 1) avoidance of a cryogenic air separation unit and 2) pre-heating the air sent to the combined power cycle, which reduces the steam requirement for shifting CO to H2 and the CO2 capture duty involved in pre-combustion CO2 capture. Relative to a conventional pre-combustion IGCC benchmark, the OPPC configuration improves the electric efficiency by about 6%-points, although the CO2 capture ratio reduces by about 6%-points. OPPC as avoids the maximum temperature limitation of Chemical Looping Combustion based plants, and can therefore benefit from efficient modern gas turbine technology operating at very high inlet temperatures. CO2 removal via physical absorption (Selexol) generally results in higher efficiencies, but lower CO2 avoidance than chemical absorption (MDEA). Plant efficiency also benefits from an increase in GSOP operating temperature, although the maximum temperature was limited to 900 °C to avoid any temperature-related challenges with oxygen carrier stability or downstream valves and filters. OPPC therefore appears to be a promising configuration for minimizing the energy penalty of CO2 capture in IGCC power plants, combining well known and proven technology blocks with a GSOP reactor cluster instead of an ASU.

Techno-economic analysis of the effects of heat integration and different carbon capture technologies on the performance of coal-based IGCC power plants

Coal-based Integrated Gasification Combined Cycle (IGCC) power plants show obvious gains over conventional pulverized coal power plants by achieving higher efficiency, lower carbon emissions and lower energy penalty for incorporating different carbon capture and storage (CCS) technologies. However, due to the lack of standardised designs, current IGCC-CCS projects are hindered by higher capital expenditures limiting their commercial implementation. Therefore, the key challenge is carrying out a techno-economic optimisation of IGCC-CCS power plants to ensure compatible power generation efficiency and accessibility. This study aims to optimise the performance of a coal-based IGCC plant with two different CCS technologies (double-stage Selexol absorption cycle and Ni-based chemical looping combustion (CLC) process) through intensive process simulation, heat integration and economic analysis. Heat integration has increased the net plant efficiency by more than 12% and decreased the levelised cost of electricity (LCOE) no less than 5 cents kWh−1. The CLC technology offered near-zero carbon emissions with higher plant efficiency and lower value of LCOE. Decreasing the CO2 capture rate by Selexol caused a decrease in LCOE and an increase in the corresponding CO2 specific emissions. Therefore, an appropriate decarbonisation scenario depends on a trade-off between the degree of carbon capture and the allowed CO2 specific emissions.

Thermo-economic analyses of IGCC power plants employing warm gas CO2 separation technology

Integrated gasification combined cycle (IGCC) power plant with dual-stage Selexol™ for carbon capture is compared to pressure swing adsorption (PSA)-based warm gas CO2 capture. Capture with Selexol™ was limited to 83.4% due to high syngas CH4 content while the efficiency was 31.11% HHV resulting in a 1st year cost of electricity (COE) of 148.6 $/MWh. Carbon capture can be increased to 88.6% and efficiency to 33.76% HHV with warm gas CO2 removal. When holding the same carbon capture level as the Selexol™ case, efficiency is increased to 34.20% HHV and after further optimization of the water gas shift (WGS) reactors to 35.63% HHV leading to a lower COE of 127.2 $/MWh. Reaction kinetic models are developed and applied for optimization of WGS reactors to convert syngas CO to CO2. Cost for warm gas carbon capture reduced to 47.5 $/tonne from 66.0 $/tonne for IGCC without carbon capture while CO2 avoided cost reduced from 89.4 $/tonne to 54.3 $/tonne. Carbon capture cost dropped from 88.0 $/tonne to 72.7 $/tonne while the CO2 avoided cost decreased from 112.2 $/tonne to 78.3 $/tonne over supercritical boiler plant without carbon capture. Furthermore, warm gas cleanup lowered the specific net water withdrawal/usage by 13.4%.

Carbon Capture at the Kemper IGCC Power Plant

The Kemper County Project demonstrated Transport Integrated Gasification (TRIG™) technology at a 2 x 1 Integrated Gasification Combined Cycle (IGCC) facility in Kemper County, Mississippi. Capable of generating up to 582 MW during syngas operations, the facility represents the largest IGCC project undertaken, the first to use lignite as fuel, the first to capture and sell CO2, and the first to produce multiple byproducts from initial startup. Featuring UOP’s SELEXOL™ (also known as SeparALL™) process, the acid gas removal (AGR) system at the plant captured carbon dioxide from the syngas and diverted it for use in enhanced oil recovery (EOR), making the Kemper facility’s carbon emissions comparable to those of a similarly sized natural-gas-fired combined cycle power plant. In addition to producing carbon dioxide, the plant also generated other saleable byproducts, including ammonia and sulfuric acid. The UOP SELEXOL process uses a physical solvent to remove acid gases from synthetic gas for the selective removal of H2S and COS and/or CO2 to very low levels in the treated gas. Very low sulfur levels of below 1 ppmv can be achieved with variable and optimized CO2 capture levels. The AGR at Kemper was the first and the largest carbon capture facility for IGCC in the world and also removed sulfur from the syngas. The process H2S absorbers remove over 99% of the sulfur. The captured H2S is later stripped from the solvent using steam heat, producing a concentrated H2S acid gas for producing sulfuric acid, while the purified solvent is refrigerated and recycled to the absorption units. Following sulfur removal, the syngas flows into CO2 absorbers, where a large portion of the CO2 in the syngas is removed. The CO2-laden solvent is regenerated by lowering the pressure of the solvent, allowing the CO2 to evolve. The removed CO2 stream was dehydrated and compressed and sold as a byproduct for EOR. The plant successfully produced electricity and all associated byproducts, while maintaining excellent safety records both during construction and plant operation. The AGR operated for over 3000 hours, processing around 1 million metric tons of syngas before the project was suspended, primarily due to the dramatic decrease in the long-term price forecast for natural gas since the time that the project was approved. Despite changes in project economics, the plant operated as intended, and just under 100,000 metric tons of carbon dioxide was delivered to the pipeline and used for enhanced oil recovery. The AGR system performed well, even at turndown conditions, processing the air-blown syngas without difficulty and making Kemper the first SELEXOL facility to process syngas produced from air-blown gasification. Syngas processing rates in the AGR were as high as 90% of full load syngas capacity, and the plant achieved the nominal design carbon capture rate of 65%, while maintaining stringent CO2 product quality requirements. The AGR sulfur capture rates were also excellent, with syngas sulfur content consistently below 0.5 ppmv, allowing the plant to easily meet its sulfur emission requirements. Commissioning on the byproduct processing systems also saw great success. The CO2 compressors, the largest two in the world with a rated power consumption of 21 MW each, performed well at supplying the CO2 to the pipeline at pressures of up to 122 barg. This paper provides a description of the process technology deployed at the Kemper Facility and discusses plant operational experience, including some of the challenges associated with commissioning a facility of this size and novelty, as well as the extended operation of the Acid Gas Removal system and CO2 compression unit.

The implications of choice between sour and sweet shift on process design and operation of an IGCC power plant integrated with a dual-stage selexol unit

In this study, it was sought to design and evaluate two process configurations of an Integrated Gasification Combined Cycle (IGCC) integrated with a dual-stage Selexol unit in which they differ in that one IGCC is configured with sour shift and the other is based on sweet shift. Incorporating water gas shift reactors consuming vast amount of shift steam into an IGCC involves significant alternations to the associated steam cycle, in addition to simply changing the location of the H2S removal step around the shift reactors. It turned out that the sweet shift case would require approximately 4.6 times more shift steam than the sour shift case, as the syngas after H2S removal did not have much steam in it. However, the energy penalties incurred by the carbon capture integration were estimated almost identical regardless of the choice between the sour and sweet shift. This is because the sour shift case would also undergo considerable reduction in power generation at steam cycle due to water quenching. In both shift cases, the high and low temperature shift reactors were sized using the reaction rate models reported in literature.

Оценки технико-экономической эффективности создания парогазовых установок с внутрицикловой газификацией для условий Монголии

Today application of combined-cycle technologies is a promising solution for implementing environmentally clean generation of electricity and heat. Due to the re-use of gas combustion energy, the efficiency of a combined-cycle power plant (CCPP) is essentially higher than that of conventional steam power units (SPU). Natural gas, a substance featuring high calorific value and environmental friendliness of its application, is used as the main fuel for a CCPP. The introduction of combined cycle technologies in the energy sector of Mongolia will make it possible to solve a number of key problems and to make a shift to a new development level of the country's economy. However, CCPPs need gaseous fuel for their operation, and only limited reserves of this fuel are available in Mongolia. The main energy fuel of the country is coal, the geological reserves of which are estimated at 150 billion tons. The integrated gasification combined cycle (IGCC) technology will help solve the problem of using coal as a fuel which is synthesized into gas. To ensure wide use of IGCC power plants in the territory of Mongolia, methods for processing solid fuel into artificial fuel gas are required. Synthesis gas, the product of solid fuel processing in the course of its gasification, will become the produced artificial fuel. The article considers the process circuit solutions that make it possible to achieve better energy efficiency and environmental friendliness of power generation at power facilities through the use of IGCC power plants. Calculated and analytical investigations of using solid fuel for IGCC power plants by producing and combusting synthesis gas in a gas turbine are carried out. Recommendations for constructing IGCC power units for the conditions of Mongolia have been developed.