The Allam Cycle is a high-performance oxy-fuel, supercritical CO 2 power cycle that offers significant benefits over traditional fossil and hydrocarbon fuel-based power generation systems. A major benefit arises in the elimination of costly precombustion acid gas removal (AGR) for sulfur- (SO x ) and nitrogen-based (NO x ) impurities by utilizing a novel downstream cleanup process that utilizes NO x first as a gas phase catalyst to effect SO x oxidation, followed by NO x removal. The basic reactions required for this process, which have been well demonstrated in several facilities for the cleanup of exhaust gasses, ultimately convert SO x and NO x species to sulfuric, nitric, and nitrous acids for removal from the supercritical CO 2 stream. The process results in simplified and significantly lower cost removal of these species and utilizes conditions inherent to the Allam Cycle that are ideally suited to facilitate this process. 8 Rivers Capital and the Energy & Environmental Research Center (EERC), supported by the state of North Dakota, the U.S. Department of Energy and an Industrial consortium from the State of North Dakota, are currently working together to test and optimize this novel impurity removal process for pressurized, semi-closed supercritical CO 2 cycles, such as the Allam Cycle. Both reaction kinetic modeling and on-site testing have been completed. Initial results show that both SO x and NO x can be substantially removed from CO 2 -rich exhaust gas containing excess oxygen under 20 bar operating pressure utilizing a simple packed spray column. Sensitivity of the removal rate to the concentration of oxygen and NO x was investigated. Follow-on work will focus on system optimization to improve removal efficiency and removal control, to minimize metallurgy and corrosion risks from handling concentrated acids, and to reduce overall capital cost and operating cost of the system.

Deposition of coal fly ash in gas turbines has been studied to support the concept of integrated gasification combined cycle (IGCC). Although particle filters are used in IGCC, small amounts of ash particles less than 5 μ m in diameter enter the gas turbine. Previous deposition experiments in the literature have been conducted at temperatures up to about 1288 °C. However, few tests have been conducted that reveal the independent effects of gas and surface temperature, and most have been conducted at gas temperatures lower than 1400 °C. The independent effects of gas and surface temperature on particle deposition in a gas turbine environment were measured using the Turbine Accelerated Deposition Facility (TADF) at Brigham Young University. Gas temperatures were measured with a type K thermocouple and surface temperatures were measured with two-color pyrometry. This facility was modified for testing at temperatures up to 1400 °C. Subbituminous coal fly ash, with a mass mean diameter of 4 μ m, was entrained in a hot gas flow at a Mach number of 0.25. A nickel base super alloy metal coupon 2.5 cm in diameter was held in this gas stream to simulate deposition in a gas turbine. The gas temperature (and hence particle temperature) governs the softening and viscosity of the particle, while the surface temperature governs the stickiness of the deposit. Two test series were therefore conducted. The first series used backside cooling to hold the initial temperature of the deposition surface (T s,i ) constant at 1000 °C while varying the gas temperature (T g ) from 1250 °C to 1400 °C. The second series held T g constant at 1400 °C while varying T s,i from 1050 °C to 1200 °C by varying the amount of backside cooling. Capture efficiency and surface roughness were calculated. Capture efficiency increased with increasing T g . Capture efficiency also initially increased with T s,i until a certain threshold temperature where capture efficiency began to decrease with increasing T s,i .

Cogeneration of synthetic natural gas (SNG) and power from coal efficiently and CO2 capture with low energy penalty during coal utilization are very important technical paths to implement clean coal technologies in China. This paper integrates a novel coal based cogeneration system with CO2 capture after chemical synthesis to produce SNG and power, and presents the energetic and exergy analysis based on the thermodynamic formulas and the use of ASPEN PLUS 11.0. In the novel system, instead of separation from the gas before chemical synthesis traditionally, CO2 will be removed from the unconverted gas after synthesis, whose concentration can reach as high as 55% before separation and is much higher than 30% in traditional SNG production system. And by moderate recycle instead of full recycle of chemical unconverted gas back into SNG synthesis, the sharp increase in energy consumption for SNG synthesis with conversion ratios will be avoided, and by using part of the chemical unconverted gas, power is cogenerated efficiently. Thermodynamic analysis shows that the benefit from both systematic integration and high CO2 concentration makes the system have good efficiency and low energy penalty for CO2 capture. The overall efficiency of the system ranges from 53%–62% at different recycle ratios. Compared to traditional single product systems (IGCC with CO2 capture for power, traditional SNG system for SNG production), the energy saving ratio (ESR) of the novel system is 16%–21%. And compared to IGCC and traditional SNG system, the energy saving benefit from cogeneration can even offset the energy consumption for CO2 separation, and thus zero energy/efficiency penalties for CO2 capture can be realized through system integration when the chemicals to power output ratio (CPOR) varies in the range of 1.0–4.6. Sensitivity analysis hints that an optimized recycle ratio of the unconverted gas and CPOR can maximize system performance (The optimized Ru for ESR maximum is around 9, 4.2, and 4.0, and the corresponding CPOR is around 4.25, 3.89, and 3.84, at τ = 4.94, 5.28 and 5.61), and minimize the efficiency penalty for CO2 capture (The optimized Ru for minimization of CO2 capture energy penalty is around 6.37 and the corresponding CPOR is around 3.97 at τ = 4.94, ε = 16.5). The polygeneration plant with CO2 capture after chemical synthesis has a good thermodynamic and environmental performance and may be an option for clean coal technologies and CO2 emission abatement.

In this paper, the issues and challenges of capturing CO2 from a pulverized coal (PC) power plant have been summarized and assessed and a hybrid power generation configuration is developed, which features a gas-turbine cogeneration unit supplying steam for stripping CO2, thereby decoupling the CO2 capture from the steam cycle of PC units. The hybrid power generation cases are modeled by using GTProTM and SteamProTM. The performance of the hybrid power plant is compared with the base case that uses extraction from the steam cycle. Retrofitting existing power plants by this hybrid concept is also assessed; performance comparison and economic analysis indicate that this kind of retrofitting is attractive to utilities with PC power generation fleet.

Carbon capture from advanced integrated gasification combined-cycle (IGCC) processes should outperform conventional coal combustion with subsequent CO2 separation in terms of efficiency and CO2 capture rates. This paper provides a thermodynamic assessment, using an exergy analysis of a syngas redox (SGR) process for generating electricity. The power island of the proposed process uses syngas produced by coal gasification and is then cleaned through a high-temperature gas desulfurization (HGD) process. Hematite (Fe2O3) is used as an oxygen carrier to oxidize the syngas. To achieve a closed-cycle operation, the reduced iron particles are first partially re-oxidized with steam and then fully re-oxidized with pressurized air. One advantage of this design is that the resulting hydrogen (using steam in the re-oxidation section) can be utilized within the same plant or be sold as a secondary product. In the proposed process, diluted hydrogen is combusted in a gas turbine. Heat integration is central to the design. Thus far, the SGR process and the HGD unit are not commercially availiable. To establish a benchmark, the rate of exergy destruction within the SGR process was compared to a coal-fed Shell gasification IGCC design with Selexol-based precombustion carbon capture. Some thermodynamic inefficiencies were found to shift from the gas turbine to the steam cycle and redox system, while the net efficiency remained almost the same. A process simulation was undertaken, using Aspen Plus and the engineering equation solver (EES).

Depending on the feedstock and the production method, the composition of syngas can include (in addition to H2 and CO) small hydrocarbons, diluents (CO2, water, and N2), and impurities (H2S, NH3, NOx, etc.). Despite this fact, most of the studies on syngas combustion do not include hydrocarbons or impurities and in some cases not even diluents in the fuel mixture composition. Hence, studies with realistic syngas composition are necessary to help in designing gas turbines. The aim of this work was to investigate numerically the effect of the variation in the syngas composition on some fundamental combustion properties of premixed systems such as laminar flame speed and ignition delay time at realistic engine operating conditions. Several pressures, temperatures, and equivalence ratios were investigated for the ignition delay times, namely 1, 10, and 35 atm, 900–1400 K, and ϕ = 0.5 and 1.0. For laminar flame speed, temperatures of 300 and 500 K were studied at pressures of 1 atm and 15 atm. Results showed that the addition of hydrocarbons generally reduces the reactivity of the mixture (longer ignition delay time, slower flame speed) due to chemical kinetic effects. The amplitude of this effect is, however, dependent on the nature and concentration of the hydrocarbon as well as the initial condition (pressure, temperature, and equivalence ratio).

Many proposed clean coal technologies for power generation couple a gasification process with a gas turbine combined cycle unit. In the gasifier, the coal is converted into a syngas which is then cleaned and fired before entering the turbine. A problem is that coal-derived syngases may contain alkali metal impurities that combine with the sulfur and chlorine from the coal to form salts that deposit on the turbine blades, causing corrosion. This paper describes a new model, applicable to most types of coal, for predicting the dewpoint temperatures and deposition rates of these sodium and potassium salts. When chlorine is present the main alkali species in the mainstream gas flow are the chlorides; but when chlorine is absent, the superoxides dominate. However, because the high-pressure turbine blades are film-cooled, they are at much lower temperatures than the mainstream gas flow and analysis then shows that the deposit is composed almost entirely of the sulfates in either liquid or solid form. This is true whether or not chlorine is present. Detailed calculations using the new model to predict the alkali salt deposition rates on three stages of an example utility turbine are presented. The calculations show how the dewpoint temperatures and deposition rates vary with the gas-phase chlorine and sulfur levels as well as with the concentrations of sodium and potassium. It is shown that the locations where corrosion is to be expected vary considerably with the type of coal and the levels of impurities present.

Even though almost all components of an integrated gasification combined cycle (IGCC) power plant are proven and mature technologies, the sheer number of them, the wide variety of competing technologies (e.g., gasifiers, gas clean-up systems, heat recovery options), and system integration options (e.g., cryogenic air separation unit and the gas turbine), including the recent addition of carbon capture and sequestration (CCS) with its own technology and integration options, render fundamental IGCC performance analysis a monumental task. Almost all published studies utilize highly complex chemical process and power plant heat balance software, including commercially available packages and in-house proprietary codes. This makes an objective assessment of comparable IGCC plant designs, performance (and cost), and other perceived advantage claims (IGCC versus other technologies, too) very difficult, if not impossible. This paper develops a coherent simplified parametric model based on fully physics-based grounds to be used for quick design performance assessment of a large variety of IGCC power plants with and without CCS. Technology parameters are established from complex model runs and supplemented by extensive literature search. The model is tested using published data to establish its confidence interval and is satisfactory to carry conceptual design analysis at a high level to identify promising alternatives and development areas and assess the realism in competing claims.

This work presents an analysis of the application of direct carbon fuel cells (DCFC) to large scale, coal fueled power cycles. DCFCs are a type of high temperature fuel cell featuring the possibility of being fed directly with coal or other heavy fuels, with high tolerance to impurities and contaminants (e.g., sulfur) contained in the fuel. Different DCFC technologies of this type are developed in laboratories, research centers or new startup companies, although at kW-scale, showing promising results for their possible future application to stationary power generation. This work investigates the potential application of two DCFC categories, both using a “molten anode medium” which can be (i) a mixture of molten carbonates or (ii) a molten metal (liquid tin) flowing at the anode of a fuel cell belonging to the solid oxide electrolyte family. Both technologies can be considered particularly interesting for the possible future application to large scale, coal fueled power cycles with CO2 capture, since they both have the advantage of oxidizing coal without mixing the oxidized products with nitrogen; thus releasing a high CO2 concentration exhaust gas. After a description of the operating principles of the two DCFCs, it is presented a lumped-volume thermodynamic model which reproduces the DCFC behavior in terms of energy and material balances, calibrated over available literature data. We consider then two plant layouts, using a hundred-MW scale coal feeding, where the DCFC generates electricity and heat recovered by a bottoming steam cycle, while the exhaust gases are sent to a CO2 compression train, after purification in appropriate cleaning processes. Detailed results are presented in terms of energy and material balances of the proposed cycles, showing how the complete system may surpass 65% lower heating value electrical efficiency with nearly complete (95%+) CO2 capture, making the system very attractive, although evidencing a number of technologically critical issues.

Our study found that burning a CO-rich gasified coal fuel, derived from an oxygen–CO 2 blown gasifier, with oxygen under stoichiometric conditions in a closed cycle gas turbine produced a highly-efficient, oxy-fuel integrated coal gasification combined cycle (IGCC) power generation system with CO 2 capture. We diluted stoichiometric combustion with recycled gas turbine exhaust and adjusted for given temperatures. Some of the exhaust was used to feed coal into the gasifier. In doing so, we found it necessary to minimize not only CO and H 2 of unburned fuel constituents but also residual O 2 , not consumed in the gas turbine combustion process. In this study, we examined the emission characteristics of gasified-fueled stoichiometric combustion with oxygen through numerical analysis based on reaction kinetics. Furthermore, we investigated the reaction characteristics of reactant gases of CO, H 2 , and O 2 remaining in the recirculating gas turbine exhaust using present numerical procedures. As a result, we were able to clarify that since fuel oxidation reaction is inhibited due to reasons of exhaust recirculation and lower oxygen partial pressure, CO oxidization is very sluggish and combustion reaction does not reach equilibrium at the combustor exit. In the case of a combustor exhaust temperature of 1573 K (1300 °C), we estimated that high CO exhaust emissions of about a few percent, in tens of milliseconds, corresponded to the combustion gas residence time in the gas turbine combustor. Combustion efficiency was estimated to reach only about 76%, which was a lower value compared to H 2 /O 2 -fired combustion while residual O 2 in exhaust was 2.5 vol%, or five times as much as the equilibrium concentration. On the other hand, unburned constituents in an expansion turbine exhaust were slowed to oxidize in a heat recovery steam generator (HRSG) flue processing, and exhaust gases reached equilibrium conditions. In this regard, however, reaction heat in HRSG could not devote enough energy for combined cycle thermal efficiency, making advanced combustion technology necessary for achieving highly efficient, oxy-fuel IGCC.

This paper presents the results of an experimental investigation on the characteristics of methane–coal-dust mixture explosion and its mitigation by ultra-fine water mist. Four E12-1-K-type fast response thermocouples, two printed circuit board (PCB) piezotronic pressure transducers were used to obtain the temperature and pressure history, while a GigaView high-speed camera was used to visualize the processes. Different methane concentrations, coal-dust concentrations, diameters of coal particles, and volumes of ultra-fine water mist were considered to investigate their effects on methane–coal-dust mixture explosion. The temperature of explosion flame, the maximum explosion overpressure, the maximum rate of overpressure rise, and the critical volume flux of ultra-fine water mist were experimentally determined. The results show that the characteristics of the methane–coal-dust mixture explosion and the mitigating effectiveness by ultra-fine water mist are influenced by the methane concentration, the coal-dust concentration, the coal-dust diameter and the applied volume flux of ultra-fine water mist. For example, both the maximum explosion overpressure and rate of overpressure rise increased with increasing of coal-dust concentrations and methane concentrations. All of the test cases indicate that ultra-fine water mist can mitigate the mixture explosion and suppress the flame propagation efficiently from the images recorded by the high-speed video camera.

This study examines the performance of a solid oxide fuel cell- (SOFC-) based integrated gasification power plant concept at the utility scale (>100 MW). The primary system concept evaluated was a pressurized ∼150 MW SOFC hybrid power system integrated with an entrained-flow, dry-fed, oxygen-blown, slagging coal gasifier and a combined cycle in the form of a gas turbine and an organic Rankine cycle (ORC) power generator. The analyzed concepts include carbon capture via oxy-combustion followed by water knockout and gas compression to pipeline-ready CO 2 sequestration conditions. The results of the study indicate that hybrid SOFC systems could achieve electric efficiencies approaching 66% [lower heating value (LHV)] when operating fueled by coal-derived clean syngas and without carbon dioxide capture. The system concept integrates SOFCs with the low-pressure turbine spool of a 50 MW Pratt & Whitney FT8-3 TwinPak gas turbine set and a scaled-up, water-cooled 20 MW version of the Pratt & Whitney (P&W) PureCycle ORC product line (approximately 260 kW). It was also found that a system efficiency performance of about 48% (LHV) is obtained when the system includes entrained-flow gasifier and carbon capture using oxygen combustion. In order to integrate the P&W FT8 into the SOFC system, the high-pressure turbine spool is removed which substantially lowers the FT8 capital cost and increases the expected life of the gas turbine engine. The impact of integrating an ORC bottoming cycle was found to be significant and can add as much as 8 percentage points of efficiency to the system. For sake of comparison, the performance of a higher temperature P&W ORC power system was also investigated. Use of a steam power cycle, in lieu of an ORC, could increase net plant efficiency by another 4%, however, operating costs are potentially much lower with ORCs than steam power cycles. Additionally, the use of cathode gas recycle is strongly relevant to efficiency performance when integrating with bottoming cycles. A parameter sensitivity analysis of the system revealed that SOFC power density is strongly influenced by design cell voltage, fuel utilization, and amount of anode recycle. To maximize the power output of the modified FT8, SOFC fuel utilization should be lower than 70%. Cathode side design parameters, such as pressure drop and temperature rise were observed to only mildly affect efficiency and power density.

Integrated gasification combined cycles (IGCCs) are considered the reference technology for high efficiency and low emission power generation from coal. In recent years, several theoretical and experimental studies in this field have been oriented toward capturing CO 2 from IGCCs through the integration of solid oxide fuel cells (SOFCs) for coal-syngas oxidation, investigating the so-called integrated gasification fuel cell cycles (IGFC). However, molten carbonate fuel cells (MCFCs) can also be a promising technology in IGFCs. After rather comprehensive research carried out by the authors on modeling and simulation of SOFC-based IGFC plants, an interesting IGFC cycle based on MCFC is assessed in this work, where plant layout is designed to exploit the capability of MCFCs of transferring CO 2 and O 2 from the oxidant side to the fuel side. Syngas produced in a high efficiency Shell gasifier is cleaned and mainly burned in a combustion turbine as in conventional IGCCs. Turbine flue gas, rich with oxygen and carbon dioxide, are then used as oxidant stream for the fuel cell at the cathode side, while the remaining clean syngas is oxidized at the anode side. In this way, the MCFC, while efficiently producing electricity, separates CO 2 from the gas turbine flue gas as in a post-combustion configuration; oxygen is also transported toward the anode side, oxidizing the remaining syngas as in an oxy-combustion mode. A CO 2 -rich stream is hence obtained at anode outlet, which can be cooled and compressed for long term storage. This configuration allows production of power from coal with high efficiency and low emission. In addition, as already highlighted in a previous study where a similar concept has been applied to natural gas-fired combined cycles, a limited fraction of the power output is generated by the fuel cell (the most expensive component), highlighting its potential also from an economic point of view. Detailed results are presented in terms of energy and material balances of the proposed cycle.

The application of solid oxide fuel cells (SOFC) in gasification-based power plants would represent a turning point in the power generation sector, allowing to considerably increase the electric efficiency of coal-fired power stations. Pollutant emissions would also be significantly reduced in integrated gasification fuel cell cycles (IGFC) considering the much lower emissions of conventional pollutants ( NO x , CO, SO x , and particulate matter) typical of fuel cell-based systems. In addition, SOFC-based IGFCs appear particularly suited to applications in power plants with CO 2 capture. This is evident by considering that SOFCs operate as air separators and partly oxidized fuel exiting the fuel cell does not contain nitrogen from air, such as in conventional oxyfuel processes. The aim of this paper is the thermodynamic analysis of a SOFC-based IGFC with CO 2 capture. In the assessed plant, syngas produced in a high efficiency Shell gasifier is used in SOFC modules after heat recovery and cleaning. Anode exhausts, still containing combustible species, are burned with oxygen produced in the air separation unit, also used to generate the oxygen needed in the gasifier; the product gas is cooled down in a heat recovery steam generator before water condensation and CO 2 compression. The plant layout is carefully designed to best exploit the heat generated in all the processes and, apart from the fuel cell exotic components, far from industrial state-of-the-art, are not included. Detailed energy and mass balances are presented for a better comprehension of the obtained results.

Thermodynamic optimization of power plants based on supercritical (SupC) and ultrasupercritical (USC) steam parameters is reported in this article. The objective is to compute the maximum attainable power plant efficiency in Indian climatic conditions using high ash (HA) indigenous coal. A unit size of 800 MWe presently under development in India is considered for energy and exergy analysis of power plants. Commercially established steam turbine parameters are used for the optimization of SupC power plant, whereas advanced steam turbine parameters currently under research and development are used for the optimization of USC power plant. The plant energy efficiency of the optimized SupC and USC power plant based on air-coal combustion (ACC) show considerable increases of 2.8 and 5.2% points, respectively compared with the current SupC ACC power plant (reference plant) being commissioned in India. The increases in plant exergy efficiency for the same power plants are 2.6 and 4.8% points and the corresponding CO 2 reductions are about 6 and 11%, respectively. The maximum possible plant energy efficiency in Indian climatic conditions using HA Indian coal is about 42.7% (USC power plant). The effect of low ash coal on plant energy and exergy efficiencies compared with HA coal is also presented. Further, the effect of oxy-coal combustion (OCC) on the plant energy and exergy efficiencies compared with the ACC is studied for the double reheat SupC and USC power plants to account for the impact of CO 2 capture. A significant reduction of 8.8 and 6.6% points in plant energy efficiency is observed for SupC and USC OCC power plants, respectively compared with the reference SupC ACC power plant.

The present regulatory requirements enforce the modification of the firing modes of existing coal-fired utility boilers and the use of coals different from those originally designed for these boilers. The reduction in SO 2 and NO x emissions was the primary motivation for these changes. Powder river basin (PRB) coals, classified as subbituminous ranked coals, can lower NO x and SO x emissions from power plants due to their high volatile content and low sulfur content, respectively. On the other hand, PRB coals have also high moisture content, low heating value, and low fusion temperature. Therefore when a power plant switches from the designed coal to a PRB coal, operational challenges were encountered. A major problem that can occur when using these coals is the severe slagging and excess fouling on the heat exchanger surfaces. Not only is there an insulating effect from deposit, but there is also a change in reflectivity of the surface. Excess furnace fouling and high reflectivity ash may cause reduction in heat transfer in the furnace, which results in higher furnace exit gas temperatures (FEGTs), especially with opposite wall burners and with a single backpass. Higher FEGTs usually result in higher stack gas temperature, increasing the reheater spray flow and therefore decreasing the boiler efficiency with a higher heat rate of the unit. A successful modification of an existing unit for firing of PRB coals requires the evaluation of the following parameters: (1) capacities or limitations of the furnace size, (2) the type and arrangement of the firing system, (3) heat transfer surface, (4) pulverizers, (5) sootblowers, (6) fans, and (7) airheaters. In the present study we used a comprehensive methodology to make this evaluation for three PRB coals to be potentially fired in a 575 MW tangential-fired boiler.

Due to the liberalization of the energy markets and the globalization of coal procurement, fuel management became of substantial importance to power plant operators, which are faced with new challenges when operating with coal types different from the originally designed ones for the specific boiler. Environmental regulations, combustion behavior, possible malfunctions and low operation, and maintenance cost became of essential importance. Fouling is one of the major challenges when new coals are being used. For that purpose we initiated a comprehensive study of fouling on the water-wall tubes in a 575 MW tangential-fired pulverized-coal utility boiler. We developed a methodology to evaluate fouling propensity of coals and specifically tested two bituminous South African coals: Billiton-Prime and Anglo-Kromdraai. The methodology is based on the adherence of ash particles on the water walls. Adherence of the ash particle depends on the particle properties, temperature, and velocity vector at the boundary layer of the water walls. In turn, the flow and temperature fields were determined by computational fluid dynamics (CFD) simulations. For CFD simulations we also needed the combustion kinetic parameters, emissivity, and thermal resistance, and they were all determined experimentally by a 50 kW test facility. Using this methodology we mapped off the locations where fouling is mostly to occur. It was found that our results fitted with the experience from the data obtained for these two coals in the Israel Electric Corporation utility boilers. The methodology developed was shown to be able to provide the fouling propensity of a certain coal, and yielded good prediction of the fouling behavior in utility boilers. Therefore, the methodology can assist in the optimization of the soot-blowing regime (location and frequency).

This paper proposes a new kind of multifunctional energy system (MES) using natural gas and coal to more efficiently and more economically produce methanol and power. Traditional chemical processes pursue high conversion ratios of chemical energy of fuels. The new MES focuses on the moderate conversion of the chemical energy of fuels. To do this, about 50% of the coal is partially gasified with pure oxygen and steam as oxidant, and then the unconverted residuals (char) and natural gas are utilized synthetically by char-fired reforming to generate syngas. The combustion of char drives the methane/steam-reforming reaction. Here, the reforming reaction is also moderately converted, and the reforming temperature is decreased 100 – 150 ° C compared with that of the conventional method. The carbon-rich syngas from the partial gasifier of coal and hydrogen-rich syngas from char-fired reformer are mixed together and converted into methanol at a proper conversion ratio (lower than that of the conventional chemical process). Finally, the unconverted syngas is used in a combined cycle as fuel for power generation. As a result, the total exergy efficiency of the new system is 55–60%. Comparing to individual systems, including the integrated gasification combined cycle and the natural gas-based methanol synthesis plants, this new system can generate 10–20% more electricity with the same quantity of fossil fuel input and methanol output. In addition, the possibility of reducing the size of gasifier, reformer, and methanol synthesis reactor may reduce investment costs accordingly. These results may provide a new way to use coal and natural gas more efficiently and economically.

In this paper, we have proposed a novel coal-based hydrogen production system with low CO 2 emission. In this novel system, a pressure swing adsorption H 2 production process and a CO 2 cryogenic capture process are well integrated to gain comprehensive performance. In particular, through sequential connection between the pressure swing absorption (PSA) H 2 production process and the CO 2 capture unit, the CO 2 concentration of PSA purge gas that enters the CO 2 capture unit can reach as high as 70%, which results in as much as 90% of CO 2 to be separated from mixed gas as liquid at a temperature of − 55 ° C . This will reduce the quantity and quality of cold energy required for cryogenic separation method, and the solidification of CO 2 is avoided. The adoption of cryogenic energy to capture CO 2 enables direct production of liquid CO 2 at low pressure and thereby saves a lot of compression energy. Besides, partial recycle of the tail gas from CO 2 recovery unit to PSA inlet can help enhance the amount of hydrogen product and lower the energy consumption for H 2 production. As a result, the energy consumption for the new system’s hydrogen production is only 196.8 GJ / tH 2 with 94% of CO 2 captured, which is 9.2% lower than that of the coal-based hydrogen production system with Selexol CO 2 removal process and is only 2.6% more than that of the coal-based hydrogen production system without CO 2 recovery. More so, the energy consumption of CO 2 recovery is expected to be reduced by 20–60% compared with that of traditional CO 2 separation processes. Further analysis on the novel system indicates that synergetic integration of the H 2 production process and cryogenic CO 2 recovery unit, along with the synthetic utilization of energy, plays a significant role in lowering energy penalty for CO 2 separation and liquefaction. The promising results obtained here provide a new approach for CO 2 removal with low energy penalty.

In this paper, pressurized oxy-fuel combustion power generation processes are modeled and analyzed based on a 350 MW subcritical reheat boiler associated with a condensing steam turbine. The performance results are obtained. Furthermore, the influences of slurry concentration and coal properties on power plant performance are investigated. An oxy-fuel configuration operating at ambient pressure is studied to compare the performance with pressurized oxy-fuel configuration. Thermodynamic analysis reveals the true potentials of the pressurized oxy-fuel process. Based on the system integration, an improved configuration is proposed in which plant efficiency of pressurized oxy-fuel process is increased by 1.36%.