Natural Gas-fired Combined Cycle Plants Research Articles

Feasibility Study of Scheme and Regenerator Parameters for Trinary Power Cycles

Natural gas-fired combined cycle plants are nowadays one of the most efficient and environmentally friendly energy complexes. High energy efficiency and low specific emissions are achieved primarily due to the high average integral temperature of heat supply in the Brayton–Rankine cycle. In this case, the main sources of energy losses are heat losses in the condenser of the steam turbine plant and heat losses with the exhaust gases of the waste heat boiler. This work is related to the analysis of the thermodynamic and economic effects in the transition from binary to trinary cycles, in which, in addition to the gas and steam–water cycles, there is an additional cycle with a low-boiling coolant. A method for the feasibility study of a waste heat recovery unit for trinary plants is proposed. The schematic and design solutions described will ensure the increased energy and economic performance of combined cycle power plants. Based on the results of the thermodynamic optimization of the structure and parameters of thermal schemes, it was found that the use of the organic Rankine cycle with R236ea freon for the utilization of the low-grade heat of a trinary plant’s exhaust gases operating from a GTE-160 gas turbine makes it possible to achieve a net electrical efficiency of 51.3%, which is a 0.4% higher efficiency for a double-circuit combined cycle gas turbine plant and a 2.1% higher efficiency for a single-circuit cycle with similar initial parameters. On the basis of the conducted feasibility study, the parameters and characteristics of the heat exchangers of the regenerative system of the waste heat recovery unit are substantiated. The use of plain fin-and-tube heat exchangers in the regenerative system of the utilization cycle is the most promising solution. It was found that the level of allowable pressure loss in the regenerator of 10 kPa and the degree of regeneration of 80% allow for maximum economic efficiency of the waste heat recovery unit.

Оцінка ефективності впровадження парогазових і ЦКШ-технологій на ТЕС України

At present, various technologies for the production of electric and heat energy are being developed and actively implemented in the world in accordance with international requirements for efficiency, economy and ecological performance. At the same time, the main attention in construction, reconstruction and modernization of power plants is given to the use of high-efficiency energy technologies for coal combustion and gasification. This paper analyzes world experience in the implementation of combined-cycle and circulating fluidized bed (CFB) technologies: combined-cycle plants (CCP) with coal gasification (with flue gas desulphurization and denitrification), combustion in atmospheric and pressurized CFB, CCP with combustion in bubbling fluidized bed under pressure, and natural gas-fired CCP in comparison with pulverized coal combustion with flue gas desulphurization and denitrification. For the new construction and reconstruction of TPP in Ukraine that burn Ukrainian coal and ensure the achievement of modern emission standards for the main pollutants, a software-and-information complex has been developed at the Institute of General Energy of the NAS of Ukraine, and a feasibility study has been carried out with comparing the average prime cost of electricity for the life cycle for advanced technologies. Our study shows that the lowest prime costs are in the case of coal combustion by the atmospheric or pressurized CFB technologies. At present, due to the high prime cost of electricity for the life cycle, the considered energy technologies are not yet competitive for the energy sector of Ukraine, although the country has a full cycle of development and production of industrial gas turbines. Combined-cycle technology is still not widely used in Ukraine. Ukrainian industry has not yet formed the necessary infrastructure for the production of CCP of high capacity, but about 80–85% of CCP equipment can be manufactured at domestic enterprises. Taking into account the high ecological performance and problems of CO2 utilization, which must be solved in the next 10-15 years, CCP and CFB technologies can be competitive for the energy sector of Ukraine in the future, and it is advisable to introduce them.

Integrated Solar Combined Cycle Power Plants: Paving the way for thermal solar

Integrated Solar Combined Cycle Power Plants (ISCCs), composed of a Concentrated Solar Power (CSP) plant and a Natural Gas-Fired Combined Cycle (NGCC) power plant, have been recently introduced in the power generation sector as a technology with the potential to simultaneously reduce fossil fuel usage and the costs of integrating solar power in an electricity system. This study quantifies the economic and environmental benefits of an ISCC power plant relative to a stand-alone CSP with energy storage, and a NGCC plant. The corresponding levelized cost of electricity (LCOE) and the Cost of Carbon Abatement (CoA) are estimated by simulating hourly operations for five U.S. locations with different solar resources and ambient temperature, under varying assumptions regarding natural gas prices, tax incentives, capacity factors, and capital costs. Results show that integrating the CSP into an ISCC reduces the LCOE of solar-generated electricity by 35–40% relative to a stand-alone CSP plant, and provides the additional benefit of dispatchability. An ISCC also outperforms a CSP with energy storage in terms of LCOE and CoA. The current LCOE of an ISCC is lower than that of a stand-alone NGCC when natural gas prices reach 13.5$/MMBtu, while its CoA is lower at a fuel price of 8.5$/MMBtu. Although, under low to moderate natural gas price conditions, a NGCC generates electricity and abates carbon emissions at a lower cost than an ISCC; small changes in the capacity factor of an ISCC relative to the NGCC, or capital cost reductions for the CSP components significantly tilt the balance in the ISCC’s favor. Hence, this technology should be seriously considered as a cost-effective baseload electricity generation alternative to speed up the transition to sustainable energy systems.

Comparison of Natural Gas Combined Cycle Power Plants with Post Combustion and Oxyfuel Technology at Different CO2 Capture Rates

Within this work a natural gas-fired combined cycle plant is investigated with post-combustion CO2 capture (PCC) and as a semi-closed oxyfuel combustion combined cycle (SCOC-CC) using process simulation tools. In most studies the CO2 capture rate of PCC units is set to 90% while the SCOC-CC is often considered for zero emission plants. To allow a comparison between the processes the capture rate needs to be taken into account. If a certain CO2 emission value is required a different capture rate may be economically attractive. The effect of the capture rate is investigated from 60% to 97.5% for PCC and from 75% to 100% for the SCOC-CC. For PCC the capture rate has a strong influence on the efficiency penalty. For a broad range of capture rates the specific heat duty is found to be approx. constant. However, for very high capture rates the heat duty strongly increases. The efficiency penalty of the SCOC-CC is much less affected by the chosen capture rate, because the duty of the air separation unit (ASU) is independent on the capture rate. However to achieve a sufficient CO2 purity a reduced capture rate can be necessary.The processes are compared regarding the loss of electrical energy per kg CO2 captured. PCC has a significantly lower specific loss for low capture rates of approx. 0.38 kWhel/kg CO2 compared to the SCOC-CC with more than 0.48 kWhel/kg CO2. For capture rates of > 90% the losses of both processes approach each other. With high purity oxygen the SCOC-CC can achieve a capture rate of 100% as well as a CO2 purity of >96 vol.-% at a specific loss of 0.49 kWhel/kg CO2.

Optimisation Potentials for the Heat Recovery in a Semi-closed Oxyfuel-combustion Combined Cycle with a Reheat Gas Turbine

Abstract Semi-closed oxyfuel-combustion combined cycle plants are one possibility to realise CCS technologies with natural gas-fired power plants. Due to the recirculation of exhaust gas the working fluid in the gas turbine consists mainly of CO2. This leads to the necessity for an increased pressure ratio to achieve the efficiency and the exhaust gas temperatures of conventional gas turbines. In this work a conventional natural gas-fired combined cycle plant with a reheat gas turbine modified for oxyfuel operation will be presented. As it is assumed that the necessary pressure ratio is not realisable with axial compressors two different scenarios are considered. On the one hand the pressure ratio is the same as in the conventional process and on the other hand the pressure ratio is set to an assumed maximum of 60. The exhaust gas temperature lies significantly above the values of the conventional plant. Generally the higher pressure ratio results in a higher net efficiency of the plant. An unchanged heat recovery process results in a loss of efficiency of at least 9.3 to 10.8%-pts. depending on the pressure ratio. Increasing the steam parameters can achieve a reduction of this loss ranging from 0.5%-pts for the high pressure ratio to 1.0%-pts for the low pressure ratio. An alternative approach for the heat recovery is the application of an internal recuperator in the gas turbine. When the achievable pressure ratio is far from the optimum value, as in the low pressure ratio case, this approach can lead to significantly lower losses of 9.1%-pts. With a higher pressure ratio the effects of the optimisation options are similar.

Evaluation of Post-Combustion CO<sub>2</sub> Capture Technologies

This paper evaluates the results of two recent studies of advanced amine-based, post-combustion CO2 capture plant designs. The first study was conducted by the IEA Greenhouse Gas R&D Programme (IEA GHG), while the second study was conducted by Parsons for the US DOEs National Energy Technology Laboratory (NETL). Fluors improved monoethanolamine (MEA) process, known as the Econamine FG PlusSM technology, is utilised for both studies. Cost and performance estimates for both pulverized coal and natural gas-fired combined cycle plants are summarized. Differences between the design bases and assumptions for the two studies are discussed. The Econamine FG PlusSM technology, as an improved process in amine-based post-combustion CO2 capture described in this paper is leading to lower increases in the cost of electricity (COE). Both the DOE/Parsons and IEA GHG studies show that the increase is now down to 42 to 43% from as high as 60 to 70% indicated from previous studies for PC plants with CO2 capture.

Effects of supplementary biomass firing on the performance of combined cycle power generation: A comparison between NGCC and IGCC plants

In the present work, effects of biomass supplementary firing on the performance of fossil fuel fired combined cycles have been analyzed. Both natural gas fired combined cycle (NGCC) and integrated coal gasification combined cycle (IGCC) have been considered in the study. The efficiency of the NGCC plant monotonically reduces with the increase in supplementary firing, while for the IGCC plant the maximum plant efficiency occurs at an optimum degree of supplementary firing. This difference in the nature of variation of the efficiency of two plants under the influence of supplementary firing has been critically analyzed in the paper. The ratings of different plant equipments, fuel flow rates and the emission indices of CO2 from the plants at varying degree of supplementary firing have been evaluated for a net power output of 200 MW. The fraction of total power generated by the bottoming cycle increases with the increase in supplementary firing. However, the decrease in the ratings of gas turbines is much more than the increase in that of the steam turbines due to the low work ratio of the topping cycle. The NGCC plants require less biomass compared to the IGCC under identical condition. A critical degree of supplementary firing has been identified for the slag free operation of the biomass combustor. The performance parameters, equipment ratings and fuel flow rates for no supplementary firing and for the critical degree of supplementary biomass firing have been compared for the NGCC and IGCC plants.

District heating in the Netherlands today: A techno-economic assessment for NGCC-CHP (Natural Gas Combined Cycle combined heat and power)

Domestic heating represents the most dominant energy function in Dutch households nowadays. Using district heat from CHP (combined heat and power) by means of a NGCC (natural gas-fired combined cycle) plants is generally acknowledged as an effective option to reduce primary energy consumption for heating. However, methods to calculate energy savings from CHP differ widely. This paper compares a number of different methods, including the method from the EU CHP Directive, to estimate primary energy savings in comparison with the typically used domestic gas-fired condensing boiler. Real hourly CHP plant performance data is used. An estimation of the CO2 mitigation cost of delivering district heat to Dutch dwellings is made. We find that supplying dwellings with district heat from an NGCC-CHP saves energy, regardless of the calculation method and for a rather wide range of reference efficiencies. CO2 mitigation costs are acceptable from a social perspective (at discount rates up to 4%, excluding fuel taxes) and negative from a private perspective (at discount rates up to 10%, including fuel taxes).

A Novel Approach of Retrofitting a Combined Cycle With Post Combustion CO2 Capture

Most state-of-the-art natural gas-fired combined cycle (NGCC) plants are triple-pressure reheat cycles with efficiencies close to 60%. However, with carbon capture and storage, the efficiency will be penalized by almost 10% units. To limit the energy consumption for a carbon capture NGCC plant, exhaust gas recirculation (EGR) is necessary. Utilizing EGR increases the CO2 content in the gas turbine exhaust while it reduces the flue gas flow to be treated in the capture plant. Nevertheless, due to EGR, the gas turbine will experience a different media with different properties compared with the design case. This study looks into how the turbomachinery reacts to EGR. The work also discusses the potential of further improvements by utilizing pressurized water rather than extraction steam as the heat source for the CO2 stripper. The results show that the required low-pressure level should be elevated to a point close to the intermediate-pressure to achieve optimum efficiency, hence, one pressure level can be omitted. The main tool used for this study is an in-house off-design model based on fully dimensionless groups programmed in the commercially available heat and mass balance program IPSEPRO. The model is based on a GE 109FB machine with a triple-pressure reheat steam cycle.

Technoeconomic evaluation of IGCC power plants for CO2 avoidance

Abstract Growing electricity demands within the next century imply an expansion in the current power plant fleet. The achievement of the above, coupled with the need for significant reductions in greenhouse gas (GHG) emissions is a challenging task. Cleaner, more efficient fossil fuel based power plant designs, combined with CO 2 capture technologies constitute an attractive option to meet this challenge in the near to medium term. Integrated gasification combined cycle (IGCC) power plants have the lowest carbon dioxide emissions among coal power plants. When combined with a CO 2 physical absorption system, substantial GHG emissions reductions can be attained. Depending on the degree of capture, the emissions can match or become less than those of natural gas fired combined cycle (NGCC) power plants. This paper is a technical and economic comparison of the performance of five plant designs in the 500 MW output range: IGCC without CO 2 capture, IGCC with 80% capture, IGCC with CO 2 emissions equal to those of a NGCC, IGCC with CO 2 and H 2 S co-capture, and NGCC without capture. ASPEN Plus™ models of the above plants were developed and the following plant performance results are discussed: net power output, efficiency, plant ancillary energy requirements and overall CO 2 emissions. Economic evaluations for all cases are presented, including the cost methodology and economic basis. The capital investment, cost of electricity and carbon dioxide mitigation costs for all plants are detailed and compared. The simulation results show that the economics favour higher capture levels in new IGCC plants. The CO 2 mitigation costs corresponding to IGCC plants with 80% capture are slightly lower than those corresponding to IGCC plants with equal emissions to those of NGCC plants (28 vs. 30 US$/tonne CO 2 avoided). The capital cost difference (per kW of net installed capacity) between the above plants is 7%, while the CO 2 emissions of the former are almost half those of the latter. IGCC plants with CO 2 and H 2 S co-capture have substantial technoeconomic advantages over IGCC plants that capture CO 2 and H 2 S separately. Based on a 577 MW IGCC, the power output decreases only to 552 MW for the co-capture case, whereas it drops to 488 MW when CO 2 and H 2 S are captured separately. The incremental capital cost of co-capture plants is 6%, and their electricity production cost increase is less than half a cent, with respect to an IGCC without capture. The CO 2 mitigation cost of co-capture plants is at least four times lower than their separate CO 2 and H 2 S capture counterparts.

A novel methodology for comparing CO 2 capture options for natural gas-fired combined cycle plants

Three concepts for capturing CO 2 from natural gas-fired combined gas/steam turbine power plants are evaluated and compared in this paper: (A) separation of CO 2 from exhaust gas coming from a standard gas turbine power plant, using chemical absorption by amine solutions. (B) Gas turbine combined cycle (CC) using a semi-closed gas turbine with near to stoichiometric combustion using oxygen from an air separation unit as an oxidizing agent. This produces CO 2 and water vapour as the combustion products. The gas turbine working fluid is mainly CO 2. (C) Decarbonization, which comprises an autothermal reforming reactor with air-blown catalytic partial oxidation of gas natural gas, a water-shift reaction and a high-pressure CO 2 capture process. The hydrogen-rich reformed fuel gas is combusted in a gas turbine CC, which is integrated (air, steam and heat) with the decarbonization process. A novel method is presented that compares power plant concepts including CO 2. Instead of using extensive thermodynamic calculations for these concepts, reaction equations for the conservation of molecular species together with specific energy consumption numbers for the different process sections are used to characterize the concepts with respect to fuel-to-electricity conversion efficiency. With a combined gas/steam turbine power plant giving 58% total fuel-to-electricity conversion efficiencies (no CO 2 capture), calculations for the concepts with CO 2 capture including CO 2 compression gave: (A) 49.6%; (B) 47.2%; and (C) 45.3%. The mechanisms leading to a reduced efficiency for concepts A–C are discussed and quantified and compared to combined gas/steam turbine with no capture of CO 2.