The results of the economic analysis explained above are illustrated by Table 8, which represents the cost for each process area from the reference case (Ref.)  and for the different NGCC plant configurations investigated in this study. It is important to highlight that according to [13, 20, 28], the scaling methodology used to calculate costs is only suitable for high level assessment and the economic results presented can reflect up to ±30% uncertainty. It is also important to mention that the economic methodology  used in this study has been validated against the different NGCC configurations outlined in the DOE/NETL report . Therefore, the calculation procedure used in this study is considered robust and repeatable. An example of this validation can be seen in Table 8, which shows that the total plant cost for the NGCC+CCS case is very similar to that of the reference plant used in the economic analysis (same configuration as in NGCC+CCS), with only 1% error in the calculated total overnight costs. Also, the differences found in the COE and COA between these configurations are mainly due to the slightly lower power output calculated for the NGCC+CCS configuration (540 MW e (see Table 3) vs 553 MW e ). This
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The gas turbine modelled in this paper is an F-frame GE gas turbine (GE 7FA.05) with a gas turbine inlet temperature 1359 o C, a gas turbine outlet temperature 604 o C and a pressure ratio 17. The bottom Rankine cycle is a triple pressure level single reheat cycle with steam cycle specification of 16.5/566/566 MPa/ o C/ o C. Further, the heat recovery steam generator (HRSG) generates both the main and the reheat steam for the steam cycle. The natural gas and air composition, along with input parameters used in the model are given in Table 1, and the basic schematic of the NGCC is shown in Figure 1. The various sections of the NGCC, including the gas turbine, steam turbine and HRSG, are indicated by bounded rectangles in Figure 1.
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The main objective of this investigation is to obtain an optimum value for the flue gas recirculation ratio in a 620 MW-Natural Gas Combined Cycle (NGCC) power plant with a 100% excess air in order to have a composition of the exhaust gas suitable for an effective absorption by amine solutions. To reach this goal, the recirculated flue gas is added to the secondary air (dilution air) used for cooling the turbine. The originality of this work is that the opti- mum value of a Flue Gas Recirculation (FGR) ratio of 0.42 is obtained from the change of the slope related to the effects of flue gas recirculation ratio on the molar percentage of oxygen in the exhaust gas. Compared to the NGCC power plant without flue gas recirculation, the molar percentage of carbon dioxide in the flue gas increases from 5% to 9.2% and the molar percentage of oxygen decreases from 10.9% to 3.5%. Since energy efficiency is the key para- meter of energy conversion systems, the impact of the flue gas recirculation on the different energy inputs and outputs and the overall efficiency of the power plant are also investigated. It is found the positive effects of the flue gas recirculation on the electricity produced by the steam turbine generator (STG) are more important than its cooling effects on the power output of the com- bustion turbine generator (CTG). The flue gas recirculation has no effects on the water pump of the steam cycle and the increase of energy consumed by the compressor of flue gas is compensated by the decrease of energy con- sumed by the compressor of fresh air. Based on the Low heating value (LHV) of the natural gas, the flue gas recirculation increases the overall efficiency of the power plant by 1.1% from 57.5% from to 58.2%.
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The final objective of increasing exergy efficiency of power plants is to reduce the consumption of fuel in order to minimize its environmental impact. The ex- ergoenvironmental analysis of power generation plants is conducted in three steps: 1) an exergetic analysis, 2) a Life Cycle Assessment (LCA) and 3) the as- signment of environmental impacts to all of the material streams of the system . Based on this methodology, Morosuk et al .  conducted an exergoenvironmental analysis with five different indicators (ECO-95, ECO-99, CExC, CML and ECO-F2006) around a cogeneration plant based on an open-cycle gas-turbine power system. The results show that the environmental impact of many energy conversion systems could be improved simply by improving their thermody- namic efficiency. Moreover, Petrakopoulou et al .  investigated the environ- mental impact of a three-pressure level combined cycle power plant. The calcu- lated value of the environmental impact of electricity (14.69 mPts/kWh) was lower than the average value 27 mPts/kWh for power plants in Europe . When including the formation of pollutants in the calculations, the value in- creased to 25.1 mPts/kWh . Açıkkalp et al .  estimated the environmental impact per kWh of produced electricity of a combined cycle power plant to be 30.5 mPts/kWh at 284 K.
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Fig. 1 illustrates the proposed cycle configuration under investigation. The diagram outlines the configuration of basic gas turbine cycle integrated with single pressure HRSG steam turbine cycle. This configuration as a whole is known as combined cycle with single pressure HRSG. Air is taken from the atmosphere at an ambient condition which enters to air compressor (AC), which in turn compresses air to a higher pressure level. The compressed air which exits the air compressor enters the combustion chamber, where the burning of natural gas in the presence of air takes place, which in succession increase its temperature and energy level. Thereafter the expansion of pressurized high temperature flue gases takes place in a gas turbine. The HRSG is installed for the recovery of heat content in gas turbine exhaust for steam generation purpose. Here single pressure HRSG is being used. HRSG is generally equipped with an economiser, evaporator and super heater. Water from the deaerator when passes through the HRSG unit, the steam of required pressure level and quality is obtained. In HRSG unit deaerated water enters the economiser by passing through boiler feed pump, where sensible heating of the feed water takes place as heat is added in the economiser at constant pressure. Then this sensibly heated water is passed through the evaporator where heat added at constant evaporator pressure is just used for the conversion of water into steam. After the phase change of the water, steam produced is then passed through the superheater for the further temperature rise and then superheated steam is expanded in a steam turbine for the power generation purpose. The expanded steam is then passed through the condenser where by phase change the steam is converted into liquid phase i.e. water. The condensate extraction pump (CEP) then supply this water to the deaerator unit where de oxidation of feed water takes place using bled steam from a steam turbine.
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Integrated Gasification Combined Cycle (IGCC) power generation technology, being developed elsewhere in the world, offers a superior alternative with better performance indicators, both in technical and environmental aspects. However, the technology as of now is, as good as being 'half-baked', as long as it is not demonstrated to be amenable to the kind of low-grade coals that are locally available. It was also seen in an earlier Techno-Economic Assessment (1992) that, IGCC appears to be a slightly costlier option. This may not be true once, the technology is fully absorbed and in fact, the unit capital costs for commercial-scale plants are supposedly lower, compared to that for a much smaller demonstration plant. Government of India, from time to time in the past, had initiated specific action plans to study the R&D efforts world over, for developing suitable clean energy technologies such as the Integrated Gasification Combined Cycle for power generation. Large-scale R&D programmes on gasification of the low grade, non-caking Indian coals were carried-out at various research institutions like IICT, Hyderabad, CFRI, Dhanbad and BHEL(R&D), Trichy.
For the analysis of the plant a computer program has been developed which consists of several control loops to calculate fluid thermodynamic properties and exergy values at various states. Also the effects of various parameters, such as compressor pressure ratio, Turbine inlet temperature, air fuel ratio and ambient temperature are studied on the cycle performance.
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CNG is a good alternative to petrol and diesel. Consumers would easily accept this form of alternative as it has low operational cost due to subsidised price and its usage could provide cleaner engine emissions. The main reason behind CNG fuel being cleaner is that natural gas is principally comprise of 90% methane, which is the simplest form of hydrocarbon. Even so, the CNG fuel available today still lack in some qualities compared to petroleum fuel. For example, CNG fuelled engines normally possess lower engine performance compared to petrol.
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Suitable modification possible in the gas turbine combined cycle such as reheat cycle, heat exchange cycle etc which will improve the efficiency. The captive power plant run as a steam power plant is taken for analysis. The power is produced by means of steam generating boilers and turbo generator. The power requirement in the plant is 10.7 MW and 153 TPH steam is generated in a day. Three boilers at a capacity of 60 TPH are used to generate the steam. The pressure is 110ATA at a temperature of 520 o C.The turbo
This paper presents the improved design of a 25 MW gas turbine power plant at Omoku in the Niger Delta area of Nigeria, using combined cycle application. It entails retrofitting a steam bot- toming plant to the existing 25 MW gas turbine plant by incorporating a heat recovery steam ge- nerator. The focus is to improve performance as well as reduction in total emission to the envi- ronment. Direct data collection was performed from the HMI monitoring screen, log books and manufacturer’s manual. Employing the application of MATLAB, the thermodynamics equations were modeled and appropriate parameters of the various components of the steam turbine power plant were determined. The results show that the combined cycle system had a total power output of 37.9 MW, made up of 25.0 MW from the gas turbine power plant and 12.9 MW (an increase of about 51%) from the steam turbine plant, having an HRSG, condenser and feed pump capacities of 42.46 MW, 29.61 MW and 1.76 MW respectively. The condenser cooling water parameters include a mass flow of 1180.42 kg/s, inlet and outlet temperatures of 29.8˚C and 35.8˚C respectively. The cycle efficiency of the dry mode gas turbine was 26.6% whereas, after modification, the combined cycle power plant overall efficiency is 48.8% (about 84% increases). Hence, SIEMENS steam tur- bine product of MODEL: SST-150 was recommended as the steam bottoming plant. Also the work reveals that a heat flow of about 42.46 MW which was otherwise being wasted in the exhaust gas of the 25 MW gas turbine power plant could be converted to 12.9 MW of electric power, thus re- ducing the total emission to the environment.
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cell voltage of 0.4997 volts, and fuel utilization coefficient of 85%. At this operating point the mass flow of fuel consumption is 1.1555 kg/s and 1.323 kg/s for hydrogen and natural gas respectively. The combustor fuel flow rate is assumed to be 0.01 kg/s for both hydrogen and natural gas fuels. The inlet fuel temperature is assumed to be 50 o C. In addition, the mass flow rate of the air used for SOFC-GT cycle depends on the type of fuel used. Air consumption for hydrogen fuel is 98.18 kg/s calculated using Eq. (44), which is nearly half the assumed value if natural gas fuel is used. Also, the value of the inlet and outlet temperatures of SOFC depends on the type of SOFC modules. For TSOFC the temperatures are 1073 k and 1273 k for the inlet and outlet flows respectively. PSOFC has a higher inlet temperature of 1123 k and a lower outlet temperature of 1223 k compared with TSOFC
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Abstract: Maximum useful work that can be obtained from a system regarding dead state conditions is defined as exergy. Nowadays exergy analysis is a widely used tool for thermo dynamical analysis of the systems because thanks to exergy analys is possible improvements on the efficiency of the systems can be asserted. Exergy, basically consists of four terms. These constituents are physical, chemical, potential and kinetic exergy. In this paper, potential and kinetic exergies are neglected, only physical and chemical exergies are considered for calculations. The equations of exergy analysis are presented in the following parts. Physical exergy shows maximum work potential of system at initial conditions while chemical exergy is related with the change of chemical composition of a system from its equilibrium conditions. This all analysis is done on a combined cycle power plant to calculate the exergy.
The studies presented in (Moore and Apt 2014; Newcomer, Blumsack, et al. 2008; Peterson et al. 2011) use economic dispatch models of the type developed in (Kelly et al. 2009; McCarthy and Yang 2010; Newcomer and Apt 2009; Sioshansi and Denholm 2010). These models do not account for the system OCs which were found in (Raichur et al. 2015) to be necessary for achieving robust estimates of economic dispatch for different types of generating units. Further, the work described in (Moore and Apt 2014; Newcomer, Blumsack, et al. 2008; Peterson et al. 2011) treat all NG units as perfect substitutes for coal units. In other words, they assume that any NG unit could replace any coal unit when NG units are cheaper to operate than coal units. As (Kaplan 2010; Macmillan et al. 2013) point out, this is unlikely and factors such as transmission constraints may limit which coal units could be substituted by NG units. For instance, if NGCC units are built in locations quite distant from coal units they may typically rely on different transmission paths and they may not be able to transmit electricity to load centers originally served by coal units. Supporting this concern, the work of (Venkatesh et al. 2012) finds that the OC associated with the minimum operating limit of coal units restricts the extent to which production from coal units could be displaced by NG units.
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A typical combined cycle plant configuration proposed by IEEE committee, its configuration is shown in Fig.3. This arrangement is made up of an air compressor, combustor, gas turbine heat recovery boiler, and a steam turbine. This functional block diagram is considered in this study, while under block models are derived separately. The functional block diagram of Fig.3 is realized using Simulink ® . It's Simulink ® model is shown in Fig.4. This model is used to simulate Perdawd power plant in the rest of the study.
Al-Sulaiman  conducted energy analysis of PTSC integrated with a steam Rankine cycle as a topping cycle and an ORC as a bottoming cycle. His study considered the energetic performance of his system and the effect of selected parameters on the size of the solar collector field. Fahad A. Al-Sulaiman  carried out detailed exergy analysis of selected thermal power systems driven by parabolic trough solar collectors (PTSCs) is presented. The power is produced using either a steam Rankine cycle (SRC) or a combined cycle, in which the SRC is the topping cycle and an organic Rankine cycle (ORC) is the bottoming cycle. Seven refrigerants for the ORC were examined: R134a, R152a, R290, R407c, R600, R600a, and ammonia. The R134a combined cycle demonstrates the best exergetic performance with a maximum exergetic efficiency of 26% followed by the R152a combined cycle with an exergetic
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turbine (coal is used as the primary energy source) is illustrated when a compressor chiller is driven by the electricity from the thermal power plant, and an extraction-condensing steam turbine is illustrated when absorption chillers are used. In Fig. 5b the combined cycle of gas and steam turbine is taken into account (natural gas is used as the primary energy source).
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The section »N ew P lant Technologies« consisted of 4 presentations, 3 foreign and 1 from Slovenia. A world technical innovation was repor ted: a gas cycle containing a mixture of liquid natrium and kalium NaK78 (Figure 1). The inner cycle, with liquid metal and a working pressure a little above 1 bar, is closed; even the electromag netic pump is completely closed and has no mo ving parts. The main advantages of the cycle with an inner cycle are very high efficiency and excel lent adaptability to momentary need for heat. The electromegnetic pump allows the mass flow of the natrium-kalium mixture to be smoothly va ried; this causes a variation of the heat flow for heating at the expense of the heat flow for rege nerative heating of working air and vice versa. One of papers presented in detail a gas turbine with electrical power of 10 MW, achieving 35 % efficiency only by producing electricity. Using the heat of the exhoust gases for heating purposes, an additional 13 MW of heat can be obtained; such simultaneous production of power and heat leads to an everall efficjeny of 82 %. Due to regenera tion, the pressure on the exit from the compres sor is only 6 bar, which is rather less than in other modern gas turbines. The temperature of
used within some industrial sectors, although they were not developed specifically for treating the mix of gases that characterise the exhaust or flue gas from coal-fired power plants. However, the potential to retrofit such systems to the large number of existing coal-fired units justifies the significant development effort needed before this can be viewed as a viable option. Commercial developments, currently taking place, are aimed at increasing PCC plant efficiency above current, state-of-the-art levels, hence the impact of fitting a CO 2 capture system to a new plant would be less than
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processes like extraction, treatment, transport and com- bustion for the generation of electricity. An assumption was made that the electricity consumed during every process of the life cycle is provided by the national en- ergy system. Table 1 show the structure (the contribution) of the primary energy resources used in the Romanian electricity sector.
Another significant finding in Figure 5 is that hydrogen produced from the refinery achieves much lower GWP than hydrogen produced from natural gas steam reforming. Considering that the refinery hydrogen is a byproduct of the petroleum refining process, and that the three buses in Perth take only 0.2% of the refinery's hydrogen output, the fuel chain in Perth is a relatively inexpensive and easily-implemented transition stage in the shift to a hydrogen economy. Western Australia is rich in natural gas, and is a net importer of transport fuel, but tradeoffs like these will be required to reduce environmental profiles while still providing economical fuel to developing technologies until suitable non-fossil resources are readily available.
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