Skip-firing (or cylinder de-activation) was assessed as a method of sampling CO 2 directly in the cylinder at higher speeds than previously possible. CO 2 was directly sampled from one cylinder of a 1 L three-cylinder gasoline engine to determine the residual gas fraction (RGF) using a fast response CO/CO 2 analyzer. Acquisition of data for similar measurements is typically limited to engine speeds of below 1300 revolutions per minute (rpm) to allow full resolution of the sample through the analyzer that has an 8 ms finite response time. In order to sample in-cylinder CO 2 at higher engine speeds, a skip-firing method is developed. By shutting off ignition intermittently during engine operation, the residual CO 2 from the last firing cycle can be measured at significantly higher engine speeds. Comparison of RGF CO 2 at low speeds for normal and skip-fire operation shows good correlation. This suggests that skip-firing is a suitable method for directly measuring internal exhaust gas recirculation up to at least 3000 rpm. The measurements obtained may provide a useful tool for validating internal exhaust gas recirculation models and could be used to calculate combustion air–fuel ratio from the CO and CO 2 content of the burned gas. These are typically complicated parameters to predict due to the slow response time and sensitivity to hydrocarbons of wide-band oxygen sensors. A differing pattern of RGF change with increasing speed was seen between normal and skip-fire operation.

This paper describes a gas turbine combined cycle (GTCC) power plant system, which addresses the three key design challenges of postcombustion CO 2 capture from the stack gas of a GTCC power plant using aqueous amine-based scrubbing method by offering the following: (i) low heat recovery steam generator (HRSG) stack gas temperature, (ii) increased HRSG stack gas CO 2 content, and (iii) decreased HRSG stack gas O 2 content. This is achieved by combining two bottoming cycle modifications in an inventive manner, i.e., (i) high supplementary (duct) firing in the HRSG and (ii) recirculation of the HRSG stack gas. It is shown that, compared to an existing natural gas-fired GTCC power plant with postcombustion capture, it is possible to reduce the CO 2 capture penalty—power diverted away from generation—by almost 65% and the overall capital cost ($/kW) by about 35%.

An annular pulsed detonation combustor (PDC) basically consists of a number of detonation tubes which are firing in a predetermined sequence into a common downstream annular plenum. Fluctuating initial conditions and fluctuating environmental parameters strongly affect the detonation. Operating such a setup without misfiring is delicate. Misfiring of individual combustion tubes will significantly lower performance or even stop the engine. Hence, an operation of such an engine requires a misfiring detection. Here, a model-based approach is used which exploits the innovation sequence calculated by a Kalman filter. The model necessary for the Kalman filter is determined based on a modal identification technique. A surrogate, nonreacting experimental setup is considered in order to develop and test these methods.

The growth in the importance of interruptible sources of energy is increasing the concerns of many electricity market regulators with respect to the reliability and stability of electricity supply. Decisions such as that to increase the number of reserve markets, their reserve requirements, or the role of reserve prices in the final electricity price have meant that generation plants are currently often operating with strategies to obtain not only large energy market quotes but also reserve ones. In this paper, a mixed integer linear programming (MILP) model is proposed to obtain the energy and reserve dispatch of a real combined cycle plant (CCP) to optimize its use on a weekly or annual basis. The dispatch is optimal in the sense that it maximizes the joint energy and reserve profits, including an estimation of the energy and reserve prices. The detailed technical and economic characteristics of the plant have been considered, such as start-ups, shut-downs, minimum hours for steam generation, supplementary firing, or natural gas contracts. The cases studies validate the main features of the mathematical model and analyze the computational efficiency in a realistic simulation.

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.

Alternative resources, such as biomass, and municipal and industrial waste are being considered as a source for the production of syngas to replace natural gas as a power turbine fuel. Pyrolysis of biomass produces a syngas composed primarily of CO, CO 2 , CH 4 , and H 2 with a medium-low lower heating value that is strongly dependent on the process boundary conditions such as the pyrolysis temperature and product residence time in the reactor. The issues associated with conventional gas turbines also apply to syngas turbines with the added complexity of the fuel and impurities. At present, syngas turbines are operated at firing temperatures similar to those of turbines fired on natural gas by increasing the fuel mass flow through the turbine. While this produces a higher turbine power output, the heat transferred to the hot flow-path vanes and blades is also greater. The aim of this paper is to report on the use of numerical modeling to analyze the fundamental impact of firing gas turbines with biomass pyrolysis syngas. To complete the analysis, the results have been compared with data from the literature on gas turbines fired with coal gasification syngas. The test engine used to perform this analysis is a General Electric GE10-2 gas turbine. The performance, aerodynamics and secondary flows were computed using proprietary software, while a commercial finite element software was used to perform the thermal and local creep analyses.

The purpose of the current work is to analyze and also to verify the operating behavior of a solid oxide fuel cell/gas turbine (GT) hybrid system in order to derive necessary requirements for an appropriate control system. The studies are carried out with a control oriented simplified dynamic model of a 25 MW e hybrid system based on a conceptual design previously presented in literature. As a specific feature additional firing of the GT combustor is investigated. First the design point is defined. Then the off-design performance is presented in terms of characteristic performance maps. Based on operating map investigations an appropriate part-load operating curve is defined with considerations given to constraints (e.g., stack temperature or surge margin), efficiency, and operational flexibility. The load range goes from 40% part-load to 105% overload. To investigate the transient behavior five open loop simulations are carried out changing different model inputs, as well as all model inputs applying a 30% load change according to the operating curve. The simulated behavior reveals that the inputs should be changed with specific care to avoid critical situations during load change.

The design-point performance characteristics of a wide variety of combined-cogeneration power plants, with different amounts of supplementary firing (or no supplementary firing), different amounts of steam injection (or no steam injection), different amounts of exhaust gas condensation, etc., without limiting these parameters to present-day limits are investigated. A representative power plant with appropriate components for these plant enhancements is developed. A computer program is used to evaluate the performance of various power plants using standard inputs for component efficiencies, and the design-point performance of these plants is computed. The results are presented as thermal efficiency, specific power, effectiveness, and specific rate of energy in district heating. The performance of the simple-cycle gas turbine dominates the overall plant performance; the plant efficiency and power are mainly determined by turbine inlet temperature and compressor pressure ratio; increasing amounts of steam injection in the gas turbine increases the efficiency and power; increasing amounts of supplementary firing decreases the efficiency but increases the power; with sufficient amounts of supplementary firing and steam injection the exhaust-gas condensate is sufficient to make up for water lost in steam injection; and the steam-turbine power is a fraction (0.1 to 0.5) of the gas-turbine power output. Regions of “optimum” parameters for the power plant based on design-point power, hot-water demand, and efficiency are shown. A method for fuel-cost allocation between electricity and hot water is recommended.

After industrial gas turbines have been in production for some amount of time, there is often an opportunity to improve or uprate the engine’s output power, cycle efficiency, or both. Typically, the manufacturer would like to provide these uprates without compromising the proven reliability and durability of the product. Further, the manufacturer would like the development of this uprate to be low cost, low risk, and result in an improvement in customer value over that of the original design. This Paper describes several options available for enhancing the performance of an existing industrial gas turbine engine, and discusses the implications for each option. Advantages and disadvantages of each option are given along with considerations that should be taken into account in selecting one option over another. Specific options discussed include dimensional scaling, improving component efficiencies, increasing massflow compressor zero staging, increasing firing temperature (thermal uprate), adding a recuperator, increasing cycle pressure ratio, and converting to a single shaft design. The implications on output power, cycle efficiency, off-design performance engine life or time between overhaul (TBO), engine cost, development time and cost, auxiliary requirements, and product support issues are discussed. Several examples are provided where these options have been successfully implemented in industrial gas turbine engines.

Twin entry radial turbines are mostly used to drive compressors of small and medium size 6-cylinder diesel engines where the available energy of the undisturbed exhaust pulses can be efficiently used to drive the turbine of a turbocharger. Three selected cylinders feed two separated manifold branches and two turbine inlets and prevent negative interaction of pressure waves and its influence on the scavenging process of the individual cylinders. In the case of a four-stroke, 4-cylinder engine, two selected cylinders, directed by the firing order, can be connected to one (of the two) separated manifold branches that feeds one turbine entry. Good utilization of the pressure pulse energy, together with typically longer periods of reduced exhaust flow can lead to good overall efficiency of the “two-pulse” system. Sometimes this system can be superior to the single manifold system with four cylinders connected to one singleentry turbine. The paper describes advantages and disadvantages of the above described exhaust systems applied to a turbocharged and aftercooled 4-cylinder Diesel engine. Comparisons supported by the analyses of the numerical and experimental results are also given in the presented paper.

The formation and capture of sulfur dioxide in a pulverized coal combustor is investigated. A two-dimensional, steady, axisymmetric code, PCGC-2 (Pulverized Coal Gasification and Combustion—two Dimensional), originally developed at Brigham Young University, has been used to simulate combustion of the pulverized coal. This paper represents part of a project to investigate simultaneously enhancing sulfur capture and particulate agglomeration in combustor effluents. Results from the code have been compared to experimental data obtained from MTCI’s (Manufacturing Technology and Conversion International) test pulse combustor, which generates sound pressure levels of ~180 dB. The overall goal behind the pulse combustor program at MTCI is to develop combustors for stationary gas turbines that use relatively inexpensive coal-based fuels. This study attempts to model the capture of sulfur dioxide when injected into a pulse combustor firing micronized coal. While this work does not presume to model the complex gas flow-field generated by the pulsating flow, the effects of the acoustic field are expressed by increased heat and mass transfer to the particles (coal/sorbent) in question. A comprehensive calcination-sintering-sulfation model for single particles was used to model the capture of sulfur dioxide by limestone sorbent. Processes controlling sulfation are external heat and mass transfer, pore diffusion, diffusion through the product layer of CaSO 4 , sintering, and calcination. The model was incorporated into the PCGC-2 program. Comparisons of exit concentrations of SO 2 showed a fairly good agreement (within ~10 percent) with the experimental results from MTCI.

Research and development work on high-temperature and high-pressure (up to 1500°F TIT and 4500 psia) topping steam turbines and associated steam generators for steam power plants as well as combined cycle plants is being carried forward by DOE, EPRI, and independent companies. Aeroderivative gas turbines and heavy-duty gas turbines both will require exhaust gas supplementary firing to achieve high throttle temperatures. This paper presents an analysis and examples of a split stream boiler arrangement for high-temperature and high-pressure topping steam turbine combined cycles. A portion of the gas turbine exhaust flow is run in parallel with a conventional heat recovery steam generator (HRSG). This side stream is supplementary fired opposed to the current practice of full exhaust flow firing. Chemical fuel gas recuperation can be incorporated in the side stream as an option. A significant combined cycle efficiency gain of 2 to 4 percentage points can be realized using this split stream approach. Calculations and graphs show how the DOE goal of 60 percent combined cycle efficiency burning natural gas fuel can be exceeded. The boiler concept is equally applicable to the integrated coal gas fuel combined cycle (IGCC).

The application of gas turbine technology to IGCC systems requires careful consideration of the degree and type of integration used during the system design phase. Although gas turbines provide the primary output and efficiency gains for IGCC systems, as compared with conventional coal-fired power generation systems, they are commercially available only in specific size ranges. Therefore, it is up to the IGCC system designer to optimize the IGCC power plant within the required output, efficiency, and site conditions by selecting the system configuration carefully, particularly for air separation unit (ASU) integration incorporated with oxygen blown gasification systems. An IGCC system, based on a generic, entrained flow, oxygen blown gasification system and a GE STAG 109FA combined cycle has been evaluated with varying degrees of ASU integration, two fuel equivalent heating values and two gas turbine firing temperatures to provide net plant output and efficiency results. The data presented illustrate the system flexibility afforded by variation of ASU integration and the potential performance gains available through the continued use of gas turbine advances. Emphasis is placed on system design choices that favor either low initial investment cost or low operating cost for a given IGCC system output.

Nondestructive characterization (NDC) methods, which can provide full-field information about components prior to and during use, are critical to the reliable application of continuous fiber ceramic matrix composites in high-firing-temperature (>1350°C) gas turbines. [For combustor liners, although they are nonmechanical load-bearing components, both thermal characteristics and mechanical integrity are vitally important.] NDC methods being developed to provide necessary information include x-ray computed tomography (mainly for through-wall density and delamination detection), infrared-based thermal diffusivity imaging, and single-wall through-transmission x-ray imaging (mainly for fiber content and alignment detection). Correlation of the data obtained from NDC methods with subscale combustor liner tests have shown positive results at thermal cycling temperatures from 700°C to 1177°C.

Developing integrated coal gasification combined-cycle systems ensures cost-effective and environmentally sound options for supplying future power generation needs. The reduction of NO x emissions and increasing the inlet temperature of gas turbines are the most significant issues in gas turbine development in Integrated Coal Gasification Combined Cycle (IGCC) power generation systems. The coal gasified fuel, which is produced in a coal gasifier of an air-blown entrained-flow type has a calorific value as low as 1/10 of natural gas. Furthermore, the fuel gas contains ammonia when a gas cleaning system is a hot type, and ammonia will be converted to nitrogen oxides in the combustion process of a gas turbine. This study is performed in a 1500°C-class gas turbine combustor firing low-Btu coal-gasified fuel in IGCC systems. An advanced rich-lean combustor of 150-MW class gas turbine was designed to hold stable combustion burning low-Btu gas and to reduce fuel NO x emissions from the ammonia in the fuel. The main fuel and the combustion air are supplied into a fuel-rich combustion chamber with strong swirl flow and make fuel-rich flame to decompose ammonia into intermediate reactants such as NHi and HCN. The secondary air is mixed with primary combustion gas dilatorily to suppress the oxidization of ammonia reactants in fuel-lean combustion chamber and to promote a reducing process to nitrogen. By testing under atmospheric pressure conditions, the authors have obtained a very significant result through investigating the effect of combustor exit gas temperature on combustion characteristics. Since we have ascertained the excellent performance of the tested combustor through our extensive investigation, we wish to report on the results.

In cooperation with U.S. Department of Energy’s Morgantown Energy Technology Center, a Westinghouse-led team is working on the second part of an 8-year, Advanced Turbine Systems Program to develop the technology required to provide a significant increase in natural gas-fired combined cycle power generation plant efficiency. This paper reports on the Westinghouse program to develop an innovative natural gas-fired advanced turbine cycle, which, in combination with increased firing temperature, use of advanced materials, increased component efficiencies, and reduced cooling air usage, has the potential of achieving a lower heating value plant efficiency in excess of 60 percent.

The integration of gas turbines and combined cycle systems with advances in coal gasification and gas stream cleanup systems will result in economically viable IGCC systems. Optimization of IGCC systems for both emission levels and cost of electricity is critical to achieving this goal. A technical issue is the ability to use a wide range of coal and petroleum-based fuel gases in conventional gas turbine combustor hardware. In order to characterize the acceptability of these syngases for gas turbines, combustion studies were conducted with simulated coal gases using full-scale advanced gas turbine (7F) combustor components. It was found that NO x emissions could be correlated as a simple function of stoichiometric flame temperature for a wide range of heating values while CO emissions were shown to depend primarily on the H 2 content of the fuel below heating values of 130 Btu/scf (5125 kJ/NM 3 ) and for H 2 /CO ratios less than unity. The test program further demonstrated the capability of advanced can-annular combustion systems to burn fuels from air-blown gasifiers with fuel lower heating values as low as 90 Btu/scf (3548 kJ/NM 3 ) at 2300°F (1260°C) firing temperature. In support of ongoing economic studies, numerous IGCC system evaluations have been conducted incorporating a majority of the commercial or near-commercial coal gasification systems coupled with “F” series gas turbine combined cycles. Both oxygen and air-blown configurations have been studied, in some cases with high and low-temperature gas cleaning systems. It has been shown that system studies must start with the characteristics and limitations of the gas turbine if output and operating economics are to be optimized throughout the range of ambient operating temperature and load variation.

The design point performance of combined cycle power plants has been steadily increasing, because of improvements both in the gas turbine technology and in the heat recovery technology, with multiple pressure heat recovery steam generators. The concern remains, however, that combined cycle power plants, like all installations based on gas turbines, have a rapid performance degradation when the load is reduced. In particular, it is well known that the efficiency degradation of a combined cycle is more rapid than that of a classical steam plant. This paper describes a methodology that can be used to evaluate the part-load performances of combined cycle units. Some examples are presented and discussed, covering multiple pressure arrangements, incorporating supplemental firing and possibly reheat. Some emphasis is put on the additional flexibility offered by the use of supplemental firing, in conjunction with schemes comprising more than one gas turbine per steam turbine. The influence of the gas turbine controls, like the use of variable inlet guide vanes in the compressor control, is also discussed.

Developing integrated coal gasification combined cycle systems ensures that Japan will have cost-effective and environmentally sound options for supplying future power generation needs. Reduction of NO x emissions and increasing the inlet temperature of gas turbines are the most significant issues in gas turbine development in IGCC. The coal gasified fuel, which is produced in a coal gasifier of air blown entrained-flow type has a calorific value as low as 1/10 of natural gas. Furthermore, the fuel gas contains ammonia when a gas cleaning system is a hot type, and ammonia will be converted to nitrogen oxides in the combustion process of a gas turbine. The study is performed in 1300°C-class gas turbine combustor firing coal-gasifier fuel in IGCC power generation systems. In the previous study [1] the advanced rich-lean combustor of 150-MW class gas turbine was designed to hold stable combustion burning low-Btu gas fuel and to reduce fuel NO x emission that is produced from the ammonia in the fuel. By testing it under atmospheric pressure conditions, we have studied the effects of fuel parameters on combustor performances and listed the basic data for development applications. In this study, by testing it under pressurized conditions, we have obtained a very significant result through investigating the effect of pressure on combustion characteristics and wish to provide herein a summary of our findings.

The paper presents an analysis of a cogeneration plant. The performance of the plant is compared to a conventional plant with separate production of process heat and power. The analysis is first- and second-law based and, therefore, quantifies the irreversibilities of the different components of each plant. In the cogeneration plant, the heat required in the boiler can be obtained either from fuel firing (condensing or back-pressure turbine plant) or from exhaust gases of a simple gas turbine (gas turbine cogeneration plant). The present study compares the two methods. The influence of the heat-to-power ratio and the process pressure on the thermal efficiency, utilization factor, and irreversibilities of the different components of each plant is presented. The results show that the total irreversibility of the cogeneration plant is lower by 38 percent compared to the conventional plant. This reduction in the irreversibility is accompanied by an increase in the thermal efficiency and utilization factor by 25 and 24 percent, respectively. The results show that most irreversible losses are due to boiler.