The state-of-the-art conventional technology for post combustion capture of CO 2 from fossil-fuelled power plants is based on chemical solvents, which requires substantial energy consumption for regeneration. Apromising alternative, available in the near future, is the application of Molten Carbonate Fuel Cells (MCFC) for CO 2 separation from post-combustion flue gases. Previous studies related to this technology showed both high efficiency and high carbon capture rates, especially when the fuel cell is thermally integrated in the flue gas path of a natural gas-fired combined cycle or an integrated gasification combined cycle plant. This work compares the application of MCFC based CO 2 separation process to pulverized coal fired steam cycles (PCC) and natural gas combined cycles (NGCC) as a ‘retrofit’ to the original power plant. Mass and energy balances are calculated through detailed models for both power plants, with fuel cell behaviour simulated using a 0D model calibrated against manufacturers’ specifications and based on experimental measurements, specifically carried out to support this study. The resulting analysis includes a comparison of the energy efficiency and CO 2 separation efficiency as well as an economic comparison of the cost of CO 2 avoided under several economic scenarios. The proposed configurations reveal promising performance, exhibiting very competitive efficiency and economic metrics in comparison with conventional CO2 capture technologies. Application as a MCFC retrofit yields a very limited (<3%) decrease in efficiency for both power plants (PCC and NGCC), a strong reduction (>80%) in CO 2 emission and a competitive cost for CO 2 avoided (25–40 €/ton).

It is well known that the history of gas turbine engines has been characterized by a very clear trend toward higher and higher operating temperatures, a growth which in the past 40 years has progressed at the impressive pace of approximately 13°C/year. Expected improvements in blade cooling techniques and advancements in materials indicate that this tendency is going to last for long time, leading to firing temperatures of over 1500°C within the next two decades. This paper investigates the impact of such temperature increase on optimal cycle arrangements and on ultimate performance improvements achievable by future advanced gas/steam cycles for large-scale power generation. Performance predictions have been carried out by a modified, improved version of a computer code originally devised and calibrated for “1990 state-of-the-art” gas/steam cycles. The range of performances to be expected in the next decades has been delimited by considering various scenarios of cooling technology and materials, including the extreme situations of adiabatic expansion and stoichiometric combustion. The results of parametric thermodynamic analyses of several cycle configurations are presented for a number of technological scenarios, including cycles with intercooling and reheat. A specific section discusses how the optimum configuration of the bottoming steam cycle changes to keep up with exhaust gas temperature increases. Calculations show that, under plausible assumptions on future technology advancements, within two decades the proper selection of plant configuration and operating parameters can yield net efficiencies of over 60%.

This paper discusses the thermodynamics of power cycles where steam or water are mixed with air (or combustion gases) to improve the performance of stationary gas turbine cycles fired on clean fuels. In particular, we consider cycles based on modified versions of modern, high-performance, high-efficiency aero-derivative engines. The paper is divided into two parts. After a brief description of the calculation method, in Part A we review the implications of intercooling and analyze cycles with steam injection (STIG and ISTIG). In Part B we examine cycles with water injection (RWI and HAT). Due to lower coolant temperatures, intercooling enables to reduce turbine cooling flows and/or to increase the turbine inlet temperature. Results show that this can provide significant power and efficiency improvements for both simple cycle and combined cycle systems based on aero-engines; systems based on heavy-duty machines also experience power output augmentation, but almost no efficiency improvement. Mainly due to the irreversibilities of steam/air mixing, intercooled steam injected cycles cannot achieve efficiencies beyond the 52–53% range even at turbine inlet temperatures of 1500°C. On the other hand, by accomplishing more reversible water-air mixing, the cycles analyzed in Part B can reach efficiencies comparable (RWI cycles) or even superior (HAT cycles) to those of conventional “unmixed” combined cycles.

Part B of this paper focuses on intercooled recuperated cycles where water is injected to improve both efficiency and power output. This concept is investigated for two basic cycle configurations: a Recuperated Water Injected (RWI) cycle, where water is simply injected downstream the HP compressor, and a Humid Air Turbine (HAT) cycle, where air/water mixing is accomplished in a counter-current heat/mass transfer column called “saturator”. For both configurations we discuss the selection and the optimization of the main cycle parameters, and track the variations of efficiency and specific work with overall gas turbine pressure ratio and turbine inlet temperature (TIT). TIT can vary to take advantage of lower gas turbine coolant temperatures, but only within the capabilities of current technology. For HAT cycles we also address the modelization of the saturator and the sensitivity to the most crucial characteristics of novel components (temperature differences and pressure drops in heat/mass transfer equipment). The efficiency penalties associated to each process are evaluated by a second-law analysis which also includes the cycles considered in Part A. For any given TIT in the range considered (1250 to 1500°C), the more reversible air/water mixing mechanism realized in the saturator allows HAT cycles to achieve efficiencies about 2 percentage points higher than those of RWI cycles: at the TIT of 1500°C made possible by intercooling, state-of-the-art aero-engines embodying the above cycle modifications can reach net electrical efficiencies of about 57% and 55%, respectively. This compares to efficiencies slightly below 56% achievable by combined cycles based upon large-scale heavy duty machines with TIT = 1280°C.

This paper presents a one-dimensional model to calculate the cooling flow of fully impingement cooled blades. The coolant is assumed to be ejected through a jet array running along the whole blade chord, with crossflow in the blade-to-blade plane from the leading edge toward the trailing edge. The simplicity of this cooling scheme translates to analytic formulations highlighting the peculiarities of impingement and the influence of geometric and fluid-dynamic parameters. Results show that the coolant flow required to maintain the blade surface under a given maximum temperature varies strongly with the jet-to-jet spacing, while the jet-to-wall gap mainly affects pressure losses. Compared to other types of convection, impingement does not afford reductions of cooling flow nor pressure losses: the basic benefits are the capability to achieve high local heat transfer coefficients and more uniform temperature distributions. Since the cooling schemes of actual gas turbine blades are substantially more complex — an elaborate combination of convection, impingement and film cooling — the present model cannot be used to predict the cooling flow required by actual engines. Nonetheless, it can give quantitative indications on the potential of impingement and help the selection of impingement array geometry.

Externally Fired Combined Cycles (EFCC) constitute one of the options allowing the use of “dirty” fuels like coal, biomass or waste in conjunction with modern, high efficiency gas turbines. This two-part paper discusses thermodynamic, technological and economic issues crucial to the successful realization of EFCCs. Part B discusses the cycle arrangement, its implications for the design and the cost of the high temperature heat exchangers, the effects of scale and the economic prospects. An “enhanced” configuration whereby the excess air sent to the combustor is limited to the minimum required for complete combustion can reach net LHV efficiencies above 50%, with relatively low high-temperature heat transfer surface requirements. Cost projections are hindered by the uncertainty on the cost of the high temperature heat exchangers. Estimates based on published and proprietary data collected by the authors indicate that EFCCs should be cost-competitive with IGCCs, especially at medium-low power outputs.

Externally Fired Combined Cycles (EFCC) are one of the options allowing the use of “dirty” fuels like coal, biomass or waste in conjunction with modern, high efficiency gas turbines. The plant concept comprises an indirect-contact ceramic heat exchanger where compressed air exiting the gas turbine compressor is heated by hot combustion gases; the combustor is placed downstream the turbine and operates at nearly atmospheric pressure. From a thermodynamic standpoint, the cycle is equivalent to a combined cycle with supplementary firing. Attainable efficiencies are higher than those achievable by steam cycles (even the most advanced ultra-supercritical), as well as those of most other coal-based technologies (PFBC and IGCC). These efficiency advantages must be weighted against the uncertainty (and risk) of the realization of high temperature ceramic heat exchangers, and the challenges for the design of the combustor. This two-part paper discusses thermodynamic, technological and economic issues crucial to the success of EFCCs, both for large scale utility service (3–400 MW e1 and more) and for medium/low scale applications (down to 30–50 MW e1 ). Part A addresses the most relevant thermodynamic and technological issues, performing comparisons with the technologies which will presumably dominate the coal-based power generation market of the next century.

The kraft process dominates pulp and paper production worldwide. Black liquor, a mixture of lignin and inorganic chemicals, is generated in this process as fiber is extracted from wood. At most kraft mills today, black liquor is burned in Tomlinson boilers to produce steam for on-site heat and power and to recover the inorganic chemicals for reuse in the process. Globally, the black liquor generation rate is about 85,000 MW fuel (or 0.5 million tonnes of dry solids per day), with nearly 50% of this in North America. The majority of presently-installed Tomlinson boilers will reach the end of their useful lives during the next 15 to 20 years. As a replacement for Tomlinson-based cogeneration, black liquor-gasifier/gas turbine cogeneration promises higher electrical efficiency, with prospective environmental, safety, and capital cost benefits for kraft mills. Several companies are pursuing commercialization of black liquor gasification for gas turbine applications. This paper presents results of detailed performance modeling of gasifier/gas turbine cogeneration systems using different black liquor gasifiers modeled on proposed commercial designs.

Black liquor, the lignin-rich byproduct of kraft pulp production, is burned in boiler/steam turbine cogeneration systems at pulp mills today to provide heat and power for onsite use. Black liquor gasification technologies under development would enable this fuel to be used in gas turbines. This paper reports preliminary economics of 100-MW e scale integrated black-liquor gasifier/combined cycles using alternative commercially-proposed gasifier designs. The economics are based on detailed full-load performance modeling and on capital and operating and maintenance costs developed in collaboration with engineers at Bechtel Corporation and Stone and Webster Engineering. Comparisons with conventional boiler/steam turbine systems are included.

Integrated Gasification Combined Cycles (IGCC) exhibit conditions particularly favourable to the sequestration of CO 2 . The concept pursued in this paper is the generation of syngas low in carbon, where most of the heating value of the coal fuel is carried by hydrogen. Catalytic shift reactors convert most of the CO in the syngas into CO 2 , which is subsequently removed by physical absorption and then compressed to make it suitable for transport and permanent storage. Energy balances, performance and cost of electricity are evaluated for two plants based on a Texaco gasifier and a large, heavy-duty gas turbine giving an overall IGCC power output between 350 and 400 MW. In one plant the raw syngas exiting the gasifier is cooled in a high-temperature, radiative cooler; in the other it is quenched by the injection of liquid water. With respect to “conventional” Texaco IGCCs, the reduction of specific CO 2 emissions by 90% reduces LHV efficiency from 5 to 7 percentage points and increases the cost of electricity of about 45%. These penalties can be reduced by accepting lower reductions of CO 2 emissions. Compared to the semi-closed cycle considered by other authors, where CO 2 is the main component of the gas turbine working fluid, the plants analyzed here exhibit higher efficiency over the whole range of specific CO 2 emissions.

Kraft pulp and paper mills generate large quantities of black liquor and byproduct biomass suitable for gasification. These fuels are used today for onsite cogeneration of heat and power in boiler/steam turbine systems. Gasification technologies under development would enable these fuels to be used in gas turbines. This paper reports results of detailed full-load performance modeling of pulp-mill cogeneration systems based on gasifier/gas turbine technologies and, for comparison, on conventional steam-turbine cogeneration technologies. Pressurized, oxygen-blown black liquor gasification, the most advanced of proposed commercial black liquor gasifier designs, is considered, together with three alternative biomass gasifier designs under commercial development (high-pressure air-blown, low-pressure air-blown, and low-pressure indirectly-heated). Heavy-duty industrial gas turbines of the 70-MW e and 25-MW e class are included in the analysis. Results indicate that gasification-based cogeneration with biomass-derived fuels would transform a typical pulp mill into a significant power exporter and would also offer possibilities for net reductions in emissions of carbon dioxide relative to present practice.

This paper assesses performances and economic viability of CO 2 removal by chemical absorption from the flue gases of natural gas-fired Combined Cycles, more specifically for two configurations: one where CO 2 is removed ahead of the stack without modifying the power cycle; the other where part of the flue gases is recirculated to the gas turbine, thereby reducing the flow to be treated by chemical absorption. In both cases sequestered CO 2 is made available at conditions suitable to storage into deep oceanic waters. Performances and cost of electricity are evaluated for systems based on large, heavy-duty turbines representative of state of the art “FA” technology. Carbon sequestration reduces net plant efficiency and power output by about 10% and increases the cost of electricity from 36 to about 50 mills/kWh. Flue gas recirculation warrants slightly higher efficiencies and lower costs. CO 2 removal is eventually compared with other strategies for the reduction of CO 2 emissions, like switching existing coal-fired steam plants to natural gas or replacing existing steam plants with conventional CCs. At current fuel prices the latter appears the option of choice, with a cost of about 25 $ per tonn of avoided CO 2 emission.

This paper assesses the integration between natural gas-fired combined cycles and grate combustors for municipal solid waste (MSW). Saturated steam generated in the grate combustor is exported to the heat recovery steam generator (HRSG) of the combined cycle, where it is superheated and then fed to a steam turbine serving both the combined cycle and the Waste-to-Energy (WTE) plant. Using a single steam turbine reduces costs and increases efficiency; in addition, superheating steam with the clean combustion products discharged by the gas turbine avoids all penalties (and extra-costs) caused by the corrosive gases generated in the grate combustor, which follow a path and are discharged from a stack completely separated from those of the CC. The optimal CC/WTE plant match is achieved when evaporation is carried out almost exclusively in the grate combustor, with the HRSG bearing the load for superheat (and reheat) and part of feedwater heating. Performance estimates for a combined cycle centered around a medium-size, heavy-duty gas turbine show that WTE/CC integration increases the efficiency of energy recovery from waste by 50% and more, with MSW disposal costs lower by 30–40%. Higher energy conversion efficiencies imply lower environmental impact, notably greater reductions of greenhouse gas emissions.

IGCC technology enables environmentally-friendly generation of electricity from high sulphur content refinery residuals and, at the same time, higher production of light and middle distillates over a wide range of crude quality. The latter represents a particularly valuable feature because environmental regulations are driving toward larger market shares of lighter and cleaner distillates and, at the same time, crude quality is declining. This paper illustrates how the integration between a refinery process and an IGCC can reduce primary energy consumption and emissions, as well as improve the economic prospects of the refinery. The analysis moves from the specific case of the ISAB-Energy plant recently completed in Priolo (Italy) and then assesses the thermodynamic, economic and environmental benefits achievable by the upgrade of the whole Italian refinery system under three sets of assumptions: IGCC with the same features and cost of the ISAB plant; advanced IGCC (LHV efficiency 46%) with a specific cost of 1400 $/kW; advanced IGCC with a specific cost of 1200 $/kW. If all Italian refineries were integrated with advanced IGCCs (with natural gas fired Combined Cycles covering the deficit of electricity production), national primary energy consumption would decrease by more than five millions tons of oil equivalent per year, CO 2 emissions would decrease by almost 15 million t/y and there would be substantial reductions of SOx, NOx and particulate emissions. If the overall cost of this restructuring were totally charged to the reduction of CO 2 emissions, each ton of avoided CO 2 emissions would costs between 4,5 to 29,3 $.

In this work, the “HRSC Optimizer”, a recently developed optimization methodology for the design of Heat Recovery Steam Cycles (HRSCs), Steam Generators (HRSGs) and boilers, is applied to the design of steam cycles for three interesting coal fired, gasification based, plants with CO 2 capture: a Fischer-Tropsch (FT) synthesis process with high recycle fraction of the unconverted FT gases (CTL-RC-CCS), a FT synthesis process with once-through reactor (CTL-OT-CCS), and an Integrated Gasification Combined Cycle (IGCC-CCS) based on the same technologies. The analysis reveals that designing efficient HRSCs for the IGCC and the once-through FT plant is relatively straightforward, while designing the HRSC for plant CTL-RC-CCS is very challenging because the recoverable thermal power is concentrated at low temperatures (i.e., below 260 °C) and only a small fraction can be used to superheat steam. As a consequence of the improved heat integration, the electric efficiency of the three plants is increased by about 2 percentage points with respect to the solutions previously published.

The viability of Mechanical Biological Treatments (MBT) is a widely discussed topic regarding Municipal Solid Waste (MSW) management in the world. Bio-drying is a MBT process that shows its best performances when the waste has a high moisture content. The purpose of bio-drying is the exploitation of the exothermic bacterial reactions for the evaporation of the highest part of the moisture in the waste with the lowest conversion of organic matter. As side effects the waste stream increases its calorific value and its composition is partially stabilized. This paper presents a simple model based on bio-drying mass and energy balances. The model takes into account the heat release from biochemical oxidation of the volatile matter, the evaporation of moisture, the heating of process air and the thermal losses, as well as changes in the chemical composition of the volatile matter that remains in the waste. Some very simple rules are identified to allow a rapid evaluation of the process performances.

This study aims at estimating the energy and environmental performances of a new cogenerative configuration of the waste to energy (WTE) plant in Piacenza. At present, the plant is authorized to treat 120,000 t/y of waste, but this limit does not represent the full treatment capacity of the facility. To exploit the plant potential and, at the same time, to reduce total equivalent emissions of the WTE process, a cogenerative configuration has been proposed. In this new scenario a back pressure turbine would be installed in parallel to the existing one, in order to supply heat to the district heating network of Piacenza and the total amount of waste treated per year by the facility would be increased to 134,100 t. The increase of 14,100 t should be satisfied by industrial and commercial waste, which would otherwise go to landfill. To compare the cogenerative scenario with the current situation, the environmental impact for the two cases has been evaluated by means of a life cycle assessment methodology. The results of the analysis show that the new configuration can ensure significant energy and environmental benefits.

We provide a detailed thermodynamic and economic analysis of two novel alternatives to the “standard” Shell coal IGCC with CO 2 capture. In the first, the syngas coolers are replaced by a “partial water quench” where the raw syngas stream is cooled and humidified via direct injection of hot water. This design is less costly, but also less efficient. The second approach retains syngas coolers but instead employs a novel WGS configuration, developed at the Energy Research Centre of the Netherlands (ECN), that requires substantially less steam to obtain the same degree of CO conversion to CO 2 , and thus increases the overall plant efficiency. We investigate how both of these innovations alter the plant’s cost and complexity, and ultimately, the levelized cost of electricity.

Chemical-Looping Combustion (CLC) is a process where fuel oxidation is carried out through an intermediate agent — a metal oxide — circulated across two fluidized bed reactors: a reduction reactor, where an endothermic reaction reduces the metal oxide and oxidizes the fuel, and an oxidation reactor, where an exothermic reaction oxidizes the metal oxide in air. Overall, the system carries out the same job of a conventional combustor, with the fundamental advantage of segregating the oxidation products (CO 2 and H 2 O) into an output flow free of nitrogen and excess oxygen. The flow exiting the reduction reactor consists of water and CO 2 , the latter readily available for liquefaction, transport and long-term storage. The hot, vitiated air from the oxidation reactor is the means to produce power through a thermodynamic cycle. This paper reports of a study supported by the ENI group to assess the potential of the integration between CLC and combined gas-steam power cycles. More specifically, we focus on four issues: (i) optimization of plant configuration; (ii) prediction of overall efficiency; (iii) use of commercial gas turbines; (iv) preliminary economic estimates. The CLC system is based on iron oxides which, to maintain their physical characteristics, must operate below 900–1000°C. Given the crucial importance of the temperature of the vitiated air generated by CLC on the performance of the combined cycle, we consider two options: (i) “unfired” systems, where natural gas is fed only to the CLC system, (ii) “fired” systems, where the vitiated air is supplementary fired to reach gas turbine inlet temperatures ranging 1000–1200°C. Results show that unfired configurations with maximum process temperature 850–1050°C and zero emissions reach net LHV plant efficiencies ranging 43–48%. Fired cycles where temperature is raised from 850 to 1200°C by supplementary firing can achieve 52% net LHV efficiency with CO 2 emission about one half of those of a state-of-the-art combined cycles. Fired configurations allow significant capital cost and fuel cost savings compared to unfired configurations; however, a carbon tax high enough to make them attractive (close to 50 €/ton) would undermine these advantages.