Biomass Utilization in Dual Combustion Gas Turbines for Distributed Power Generation in Mediterranean Countries

2011 ◽  
Author(s):  
Sergio Mario Camporeale ◽  
Bernardo Fortunato ◽  
Antonio Marco Pantaleo ◽  
Domenico Sciacovelli
Keyword(s):  
Power Plant ◽  
Natural Gas ◽  
Gas Turbines ◽  
Fixed Bed ◽  
Combined Cycle ◽  
Biomass Energy ◽  
Inlet Temperature ◽  
Optimal Size ◽  
Direct Combustion ◽  
Mediterranean Countries

In Mediterranean regions, such as Puglia in Italy, the supply chain constraints (i.e. local biomass availability, logistics of supply, storage and seasonality issues) limit the optimal size of a biomass fired power plant in a range of 5–15 MWe. In this scenario, innovative Dual Combustion Externally Fired Gas Turbine (DCGT) Power Plants cofired by natural gas and biomass are examined. For this purpose, biomass external firing is explored under two alternatives: direct combustion of solid biomass and atmospheric fixed bed biomass gasification with air. The proposed cycles are analyzed considering both the Net Overall Electric Efficiency and the Marginal Efficiency of biomass energy conversion, defined for the cofiring of biomass and natural gas. Since natural gas represents a quite expensive fossil fuel resource, a Marginal Efficiency higher than zero indicates the convenience to burn natural gas in this typology of power plant rather than in traditional Combined Cycle with higher efficiency. The energy analysis has been carried out by varying pressure ratio, turbine inlet temperature, heat exchanger efficiency and considering the further option of steam injection. The results of the thermodynamic assessment highlight that the gasification should be preferred to the direct combustion of biomass because of the higher marginal efficiency, although the net overall electric efficiencies of the two plants are almost the same (31%).

Co-Utilization of Biomass and Natural Gas in an Existing Powerplant Through Primary Steam Reforming of Natural Gas

2006 ◽  
Author(s):  
Frank Delattin ◽  
Svend Bram ◽  
Jacques De Ruyck
Keyword(s):  
Power Plant ◽  
Natural Gas ◽  
Gas Turbines ◽  
Waste Heat ◽  
Internal Combustion ◽  
Combined Cycle ◽  
Biomass Energy ◽  
Small Scale ◽  
Combined Cycles ◽  
External Combustion

Power production from biomass can occur through external combustion (e.g. steam cycles, Organic Rankine Cycles, Stirling engines), or internal combustion after gasification or pyrolysis (e.g. gas engines, IGCC). External combustion has the disadvantage of delivering limited conversion efficiencies (max 35%). Internal combustion has the potential of high efficiencies, but it always needs a severe and mostly problematic gas cleaning. The present article proposes an alternative route where advantages of external firing are combined with potential high efficiency of combined cycles through co-utilization of natural gas and biomass. Biomass is burned to provide heat for partial reforming of the natural gas feed. In this way, biomass energy is converted into chemical energy contained in the produced syngas. Waste heat from the reformer and from the biomass combustor is recovered through a waste heat recovery system. It has been shown in previous papers that in this way biomass can replace up to 5% of the natural gas in steam injected gas turbines and combined cycles, whilst maintaining high efficiencies [1,2]. The present paper proposes the application of this technique as retrofit of an existing combined cycle power plant (Drogenbos, Belgium) where 1% of the natural gas input would be replaced by wood pellets. This represents an installed biomass capacity of 5 MWth from biomass which could serve as a small scale demonstration. The existing plant cycle is first simulated and validated. The simulated cycle is next adapted to partially run on biomass and a retrofit power plant cycle layout is proposed.

Part-Load Operation of Gas Turbines Induced by Co-Gasification of Coal and Biomass in an Integrated Gasification Combined Cycle Power Plant

2021 ◽  
Author(s):  
Silvia Ravelli
Keyword(s):  
Power Plant ◽  
Gas Turbines ◽  
Combined Cycle ◽  
Inlet Guide Vane ◽  
Inlet Temperature ◽  
Fuel Quality ◽  
Integrated Gasification Combined Cycle ◽  
Part Load ◽  
Wide Range ◽  
Integrated Gasification

Abstract This study takes inspiration from a previous work focused on the simulations of the Willem-Alexander Centrale (WAC) power plant located in Buggenum (the Netherlands), based on integrated gasification combined cycle (IGCC) technology, under both design and off-design conditions. These latter included co-gasification of coal and biomass, in proportions of 30:70, in three different fuel mixtures. Any drop in the energy content of the coal/biomass blend, with respect to 100% coal, translated into a reduction in gas turbine (GT) firing temperature and load, according to the guidelines of WAC testing. Since the model was found to be accurate in comparison with operational data, here attention is drawn to the GT behavior. Hence part load strategies, such as fuel-only turbine inlet temperature (TIT) control and inlet guide vane (IGV) control, were investigated with the aim of maximizing the net electric efficiency (ηel) of the whole plant. This was done for different GT models from leading manufactures on a comparable size, in the range between 190–200 MW. The influence of fuel quality on overall ηel was discussed for three binary blends, over a wide range of lower heating value (LHV), while ensuring a concentration of H2 in the syngas below the limit of 30 vol%. IGV control was found to deliver the highest IGCC ηel combined with the lowest CO2 emission intensity, when compared not only to TIT control but also to turbine exhaust temperature control, which matches the spec for the selected GT engine. Thermoflex® was used to compute mass and energy balances in a steady environment thus neglecting dynamic aspects.

Performance and Cost Analysis of Advanced Gas Turbine Cycles With Precombustion CO2 Capture

2008 ◽  
Vol 131 (2) ◽  
Author(s):  
Stéphanie Hoffmann ◽  
Michael Bartlett ◽  
Matthias Finkenrath ◽  
Andrei Evulet ◽  
Tord Peter Ursin
Keyword(s):  
High Pressure ◽  
Power Plant ◽  
Natural Gas ◽  
Gas Turbine ◽  
Co2 Capture ◽  
Gas Turbines ◽  
High Efficiency ◽  
Combined Cycle ◽  
Co2 Separation ◽  
The Cost

This paper presents the results of an evaluation of advanced combined cycle gas turbine plants with precombustion capture of CO2 from natural gas. In particular, the designs are carried out with the objectives of high efficiency, low capital cost, and low emissions of carbon dioxide to the atmosphere. The novel cycles introduced in this paper are comprised of a high-pressure syngas generation island, in which an air-blown partial oxidation reformer is used to generate syngas from natural gas, and a power island, in which a CO2-lean syngas is burnt in a large frame machine. In order to reduce the efficiency penalty of natural gas reforming, a significant effort is spent evaluating and optimizing alternatives to recover the heat released during the process. CO2 is removed from the shifted syngas using either CO2 absorbing solvents or a CO2 membrane. CO2 separation membranes, in particular, have the potential for considerable cost or energy savings compared with conventional solvent-based separation and benefit from the high-pressure level of the syngas generation island. A feasibility analysis and a cycle performance evaluation are carried out for large frame gas turbines such as the 9FB. Both short-term and long-term solutions have been investigated. An analysis of the cost of CO2 avoided is presented, including an evaluation of the cost of modifying the combined cycle due to CO2 separation. The paper describes a power plant reaching the performance targets of 50% net cycle efficiency and 80% CO2 capture, as well as the cost target of 30$ per ton of CO2 avoided (2006 Q1 basis). This paper indicates a development path to this power plant that minimizes technical risks by incremental implementation of new technology.

Performance and Cost Analysis of Advanced Gas Turbine Cycles With Pre-Combustion CO2 Capture

2008 ◽  
Author(s):  
Ste´phanie Hoffmann ◽  
Michael Bartlett ◽  
Matthias Finkenrath ◽  
Andrei Evulet ◽  
Tord Peter Ursin
Keyword(s):  
High Pressure ◽  
Power Plant ◽  
Natural Gas ◽  
Gas Turbine ◽  
Co2 Capture ◽  
Gas Turbines ◽  
High Efficiency ◽  
Combined Cycle ◽  
Co2 Separation ◽  
The Cost

This paper presents the results of an evaluation of advanced combined cycle gas turbine plants with pre-combustion capture of CO2 from natural gas. In particular, the designs are carried out with the objectives of high efficiency, low capital cost and low emissions of carbon dioxide to the atmosphere. The novel cycles introduced in this paper are comprised of a high-pressure syngas generation island, in which an air-blown POX reformer is used to generate syngas from natural gas, and a power island, in which a CO2-lean syngas is burnt in a large frame machine. In order to reduce the efficiency penalty of natural gas reforming, a significant effort is spent evaluating and optimizing alternatives to recover the heat released during the process. CO2 is removed from the shifted syngas using either CO2 absorbing solvents or a CO2 membrane. CO2 separation membranes, in particular, have the potential for considerable cost or energy savings compared to conventional solvent-based separation and benefit from the high pressure level of the syngas generation island. A feasibility analysis and a cycle performance evaluation are carried out for large frame gas turbines such as the 9FB. Both short term and long term solutions have been investigated. An analysis of the cost of CO2 avoided is presented, including an evaluation of the cost of modifying the combined cycle due to CO2 separation. The paper describes a power plant reaching the performance targets of 50% net cycle efficiency and 80% CO2 capture, as well as the cost target of 30$ per ton of CO2 avoided. This paper indicates a development path to this power plant that minimizes technical risks by incremental implementation of new technology.

Short-Term Optimization of a Combined Cycle Power Plant Integrated with an Inlet Air Conditioning Unit

2021 ◽  
Author(s):  
Weimar Mantilla ◽  
Jose Angel Garcia ◽  
Rafael Guédez ◽  
Alessandro Sorce
Keyword(s):  
Power Plant ◽  
Electricity Markets ◽  
Gas Turbines ◽  
Air Conditioning ◽  
Linear Optimization ◽  
Operation Mode ◽  
Combined Cycle ◽  
Mixed Integer ◽  
Inlet Temperature ◽  
The Impact

Abstract Under new scenarios with high shares of renewable electricity, combined cycle gas turbines (CCGT) are required to improve their flexibility to help balance the power system. Simultaneously, liberalization of electricity markets and the complexity of its hourly price dynamics are affecting the CCGT profitability, leading the need for optimizing its operation. An inlet air conditioning unit (ICU) offers the benefit of power augmentation and "minimum environmental load" (MEL) reduction by controlling the gas turbine inlet temperature using cold thermal energy storage and a heat pump. Consequently, an evaluation of a CCGT integrated with this unit including a day-ahead optimized operation strategy was developed in this study. To establish the hourly dispatch of the power plant and the operation mode of the inlet conditioning unit, a mixed-integer linear optimization (MILP) was formulated, aiming to maximize the operational profit of the plant within a 24-hours horizon. To assess the impact of the unit operating under this dispatch strategy, historical data have been used to perform annual simulations of a reference power plant located in Turin, Italy. Results indicate that the power plant's operational profit increase by achieving a wider operational range during peak and off-peak periods. For the specific case study, it is estimated that the NPV of the CCGT integrated with the ICU is 0.5% higher than the CCGT without it. Results also show that the unitc reduces the MEL by approximately 1.34% and can increase the net power output by 0.17% annually.

Adaptability of the Solar Advanced Turbine Systems to Biomass and Coal Derived Fuels

1996 ◽  
Author(s):  
David J. White ◽  
Richard T. LeCren ◽  
Chaur S. Wen
Keyword(s):  
Natural Gas ◽  
Gas Turbines ◽  
Alternative Fuels ◽  
Combined Cycle ◽  
Department Of Energy ◽  
Integrated Gasification Combined Cycle ◽  
Turbine Engine ◽  
Direct Combustion ◽  
Pulverized Fuel ◽  
Integrated Gasification

SolarTurbines Incorporated (Solar) is developing the technologies that are to be used for a highly efficient, recuperated, Advanced Turbine System (ATS) that is aimed at the dispersed power generation market. With ultra-low-emissions in mind the primary fuel selected for this gas turbine engine system is natural gas. Although this gas fired ATS (GFATS) will primarily employ natural gas, the use of other fuels, particularly those derived from coal and renewable resources cannot be overlooked. The enabting technologies necessary to direct-fire coal in gas turbines were developed during the 1980s. This Solar development, co-sponsored by the U.S. Department of Energy (DOE), resulted in the testing of a full size coal-water-slurry fired combustion system. In parallel with this program the DOE funded the development of integrated gasification combined-cycle systems (IGCC). This report describes the limitations of the Solar ATS (recuperated engine) and how these limitations lead to a recommended series of modifications that will allow the use of these alternative fuels. Three approaches have been considered: direct-fired combustion using either a slagging combustor, or a pressurized fluidized bed (PFBC), externally or indirectly fired approaches using pulverized fuel, and external gasification of the fuel with subsequent direct combustion of the secondary fuel. Each of these approaches requires substantial hardware and system modifications for efficient fuel utilization. The integration issues are discussed in the sections below and a recommended approach for gasification is presented.

scholarly journals Technical Economic and Environmental analysis of Chemical Looping versus oxyfuel combustion for NGCC power plant

2021 ◽  
Vol 312 ◽  
pp. 08019
Author(s):  
Pietro Bartocci ◽  
Alberto Abad ◽  
Arturo Cabello ◽  
Mauro Zampilli ◽  
Giulio Buia ◽  
...  
Keyword(s):  
Power Plant ◽  
Natural Gas ◽  
Gas Turbines ◽  
Internal Combustion Engines ◽  
Combined Cycle ◽  
Chemical Looping ◽  
Low Carbon ◽  
Power Capacity ◽  
Oxyfuel Combustion ◽  
Low Carbon Technologies

The Power Sector is undergoing a rapid technological change with respect to implementation of low carbon technologies. The IEA Energy Outlook 2017 shows that the investments in Renewables for the first time are equal to those on the fossil sources. It is likely that the conventional gas turbines and internal combustion engines will need to be integrated in systems employing biofuels and/or CCUS (Carbon Capture Usage and Storage). Also, the European Union is moving rapidly towards low carbon technologies (i.e. Energy Efficiency, Smart Grids, Renewables and CCUS), see the Energy Union Strategy. Currently 28% of the installed power capacity in Europe is based on natural gas plants. Gas-based power capacity has reached 418 GW in 2016 and is likely to continue to grow in the future. To efficiently capture the carbon dioxide emissions generated by the combustion of natural gas in the combustion chamber a possible solution could be to adopt new combustion processes, like Chemical Looping Combustion. The combination of CLC and GTs can decrease the efficiency of a combined cycle power plant from 60% to about 40.34%. These performances influence costs and environmental burdens and this is also the same for oxyfuel combustion, which is a competing technology to realize CCS. This paper, starting from literature mass and energy balances of a conventional combined cycle, a combined cycle coupled with chemical looping combustor and a combined cycle coupled with oxyfuel combustion, calculates the reduction of CO2 emissions which can be achieved during the whole life cycle of the power plant and then identifies the value of the carbon credit which is needed to have an interesting payback period for such kind of investment.

Numerical Simulations of the Effects of Changing Fuel for Turbines Fired by Natural Gas and Syngas

2007 ◽  
Author(s):  
Adrian S. Sabau ◽  
Ian G. Wright
Keyword(s):  
Natural Gas ◽  
Numerical Simulations ◽  
Mass Flow ◽  
Gas Turbines ◽  
Combined Cycle ◽  
Coolant Flow ◽  
Inlet Temperature ◽  
Flow Rates ◽  
Hot Gas ◽  
First Case

Gas turbines in integrated gasification combined cycle (IGCC) power plants burn a fuel gas (syngas) in which the proportions of hydrocarbons, H2, CO, water vapor, and minor impurity levels may vary significantly from those in natural gas, depending on the input feed to the gasifier and the gasification process. A data structure and computational methodology is presented for the numerical simulation of a turbine thermodynamic cycle for various fuel types, air/fuel ratios, and coolant flow rates. The approach used allowed efficient handling of turbine components and different variable constraints due to fuel changes. Examples are presented for a turbine with four stages and cooled blades. The blades were considered to be cooled in an open circuit, with air provided from appropriate compressor stages. Results are presented for the temperatures of the hot gas, alloy surface (coating-superalloy interface), and coolant, as well as for cooling flow rates. Based on the results of the numerical simulations, values were calculated for the fuel flow rates, airflow ratios, and coolant flow rates required to maintain the superalloy in the first stage blade at the desired temperature when the fuel was changed from natural gas (NG) to syngas (SG). One NG case was conducted to assess the effect of coolant pressure matching between the compressor extraction points and corresponding turbine injection points. It was found that pressure matching is a feature that must be considered for high combustion temperatures. The first series of SG simulations was conducted using the same inlet mass flow and pressure ratios as those for the NG case. The results showed that higher coolant flow rates and a larger number of cooled turbine rows were needed for the SG case. Thus, for this first case, the turbine size would be different for SG than for NG. In order to maintain the original turbine configuration (i.e., geometry, diameters, blade heights, angles, and cooling circuit characteristics) for the SG simulations, a second series of simulations was carried out by varying the inlet mass flow while keeping constant the pressure ratios and the amount of hot gas passing the first vane of the turbine. The effect of turbine matching between the NG and SG cases was approximately 10°C, and 8 to 14% for rotor inlet temperature and total cooling flows, respectively. These results indicate that turbine-compressor matching, before and after fuel change, must be included in turbine models. The last stage of the turbine, for the SG case, experienced higher inner wall temperatures than the corresponding case for NG, with the temperature of the vane approaching the maximum allowable limit.

Low CO2 Combustion System Retrofits for Existing Heavy Duty Gas Turbines

2008 ◽  
Author(s):  
Peter J. Stuttaford ◽  
Khalid Oumejjoud
Keyword(s):  
Power Plant ◽  
Natural Gas ◽  
Gas Turbine ◽  
Gas Turbines ◽  
Power Plants ◽  
Combined Cycle ◽  
Premixed Combustion ◽  
Combustion System ◽  
Heavy Duty ◽  
Fuel Processing

CO2 emissions generated by power plants make up a significant portion of global carbon emissions. Although there has been a great deal of focus on new power sources incorporating state of the art environmental protection systems, there has been little focus on addressing the issues of existing power plants. The purpose of this work is to address the options available to existing gas turbine based power plants to retrofit CO2 reduction measures cost effectively at the source of emissions, the combustor. Pre-combustion decarbonization is a highly efficient method of carbon removal, as only a small fraction of the gas turbine system flow needs to be addressed. This results in the requirement to burn a hydrogen based fuel, which presents challenges due to its highly reactive nature. The properties of hydrogen/syngas combustion are reviewed with emphasis on solutions for premixed combustion systems. Premixed combustion as opposed to diffusion combustion systems are key to retrofit solutions for existing gas turbines. Premixed systems provide the life cycle cost benefit, and heat rate benefit of not requiring the addition of diluent to the cycle to control emissions. Fuel flexibility is critical for retrofit systems, allowing operators to run on high hydrogen fuels as well as back-up standard natural gas to maximize power plant availability. Pre-combustion decarbonization may occur remote from the power plant at a centralized fuel processing facility, or it may be integrated into the combined cycle gas turbine power plant. Existing combined cycle power plants operating on natural gas could be modified to incorporate fuel decarbonization into the cycle, minimizing the parasitic loss of such a system while capturing carbon credits which are likely to become of increasing monetary value. An example cycle to address such integrated systems is presented. The focus of this work is to present a cycle to provide decarbonized fuel, cost effectively, from existing natural gas systems, as well as centralized coal/petcoke based fuel processing facilities. An additional focus is on the combustion system design requirements to burn such fuels, which are retrofitable to existing heavy duty gas turbine based power plants.

Sign in / Sign up

Export Citation Format

Share Document