Performance of a Biomass Integrated Gasification Combined Cycle CHP Plant Supplying Heat to a District Heating Network

2000 ◽  
Author(s):  
Simon Harvey
Keyword(s):  
District Heating ◽  
Heating System ◽  
Combined Cycle ◽  
Production Costs ◽  
Integrated Gasification Combined Cycle ◽  
International Consensus ◽  
District Heating System ◽  
Simulated Performance ◽  
Integrated Gasification ◽  
Performance Results

This paper examines a Biomass Integrated Gasification Combined Cycle (BIGCC) CHP plant using atmospheric air-blown gasification with wet cold gas clean-up and flue gas drying of the biomass feed stream. The plant provides heat and power to a medium sized municipality. The paper presents simulated performance results obtained using GateCycle software, and also presents results for the associated economy and CO2 emissions of the district heating system. The computed production costs of the cogenerated electricity are uncompetitively high, given current conditions in Sweden. In order to become competitive, international consensus must be reached on the level of economic advantage to be attributed to the “green” electric power produced by such a plant. However, likely price incentives for “green” power will probably be insufficient for BIGCC-CHP plants to become economically attractive. Therefore further effort is needed to improve the technology, reduce the investment costs, and identify options for longer annual operating times than those usually adopted for CHP plants coupled to district heating plants.

A System Performance and Economics Analysis of IGCC With Supercritical Steam Bottom Cycle Supplied With Varying Blends of Coal and Biomass Feedstock

2011 ◽  
Author(s):  
Henry A. Long ◽  
Ting Wang
Keyword(s):  
Carbon Capture ◽  
Ghg Emissions ◽  
Capital Cost ◽  
Combined Cycle ◽  
Production Costs ◽  
Integrated Gasification Combined Cycle ◽  
Cost Of Electricity ◽  
Biomass Ratio ◽  
Integrated Gasification ◽  
Steam Cycle

In recent years, Integrated Gasification Combined Cycle Technology (IGCC) has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration. Great efforts have been continuously spent on investigating various ways to improve the efficiency and further reduce the greenhouse gas (GHG) emissions of such plants. This study focuses on investigating two approaches to achieve these goals. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as co-feedstock to reduce carbon footprint as well as SOx and NOx emissions. Employing biomass as a feedstock to generate fuels or power has the advantage of being carbon neutral or even becoming carbon negative if carbon is captured and sequestered. Due to a limited supply of feedstock, biomass plants are usually small, which results in higher capital and production costs. In addition, biomass can only be obtained at specific times in the year, meaning the plant cannot feasibly operate year-round, resulting in fairly low capacity factors. Considering these challenges, it is more economically attractive and less technically challenging to co-combust or co-gasify biomass wastes with coal. The results show that supercritical IGCC the net plant efficiency increases with increased biomass blending in the all cases. For both subcritical and supercritical cases, the efficiency increases initially from 0% to 10% (wt.) biomass, and decreases thereafter. However, the efficiency of the blended cases always remains higher than that of the pure coal baseline cases. The emissions (NOx, SOx, and effective CO2) and the capital cost all decrease as biomass ratio increases, but the cost of electricity increases with biomass ratio due to the high cost of the biomass used. Finally, implementing a supercritical steam cycle is shown to increase the net plant output power by 13% and the thermal efficiency by about 1.6 percentage points (or 4.56%) with a 6.7% reduction in capital cost, and a 3.5% decrease in cost of electricity.

Application of Predictive Control in District Heating Systems

1993 ◽  
Vol 207 (3) ◽  
pp. 157-163 ◽  
Author(s):  
O P Palsson ◽  
H Madsen ◽  
H T Søgaard
Keyword(s):  
Predictive Control ◽  
District Heating ◽  
Real Data ◽  
Heating System ◽  
Production Costs ◽  
Model Parameters ◽  
District Heating System ◽  
Heating Systems ◽  
District Heating Systems ◽  
Heat Requirement

In district heating systems, and in particular if the heat production takes place at a combined heat and power (CHP) plant, a reasonable control strategy is to keep the supply temperature from the district heating plant as low as possible. However, the control is subject to some restrictions, for example, that the total heat requirement for all consumers is supplied at any time and each individual consumer is guaranteed some minimum supply temperature at any time. A lower supply temperature implies lower heat loss from the transport and the distribution network, and lower production costs. A district heating system is an example of a non-stationary system, and the model parameters have to be time varying. Hence, the classical predictive control theory has to be modified. Simulation experiments are performed in order to study the performance of modified predictive controllers. The systems are, however, described by transfer function models identified from real data.

Syngas Production and Combustion Turbine Operation With Hydrogen-Rich Fuel at the Kemper County IGCC

2018 ◽  
Author(s):  
Matt Nelson ◽  
Pannalal Vimalchand ◽  
WanWang Peng ◽  
Tim Lieuwen ◽  
Diane Revay Madden ◽  
...  
Keyword(s):  
Gas Turbines ◽  
Combined Cycle ◽  
Plant Design ◽  
Integrated Gasification Combined Cycle ◽  
High Hydrogen ◽  
Syngas Production ◽  
And Performance ◽  
Integrated Gasification ◽  
Performance Results ◽  
Turbine Design

The Kemper County Project has demonstrated Transport Integrated Gasification (TRIG™) at a 2-on-1 Integrated Gasification Combined-Cycle (IGCC) facility located in Kemper County, Mississippi. Kemper is the largest IGCC project in the world, the first to use lignite as fuel, the first to capture and sell CO2, and the first to produce multiple byproducts from initial startup. The facility features two Siemens SGT6-5000F gas turbines, each capable of operating on a high-hydrogen syngas produced in the Transport Gasifiers from locally mined lignite. Using high-hydrogen syngas requires unique modifications to the combustion turbine design. Flame-diffusion combustors, rather than dry low-NOX designs, prevent flashback caused by the high hydrogen content of the syngas. Also, ports added to the turbine compressor casing allow air to be extracted from the compressor and used elsewhere in the plant, supplying up to one half of the air required by the gasifier. The Kemper facility has achieved the integrated operation of both gasifiers, including the production of electricity from syngas by both combustion turbines. Turbine operation on the high hydrogen syngas was smooth both during normal operations and during transitions, with efficiencies meeting or exceeding expectations. This paper describes the Kemper plant design, focusing on the combustion turbine design unique to Kemper. The paper also discusses turbine design challenges specific to Kemper, provides an overview of the robust control scheme used on both syngas and natural gas co-firing operations, and provides preliminary operational and performance results, including inspection findings.

scholarly journals The Impact of Optimal Demand Response Control and Thermal Energy Storage on a District Heating System

Energies ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1678 ◽  
Author(s):  
Sonja Salo ◽  
Aira Hast ◽  
Juha Jokisalo ◽  
Risto Kosonen ◽  
Sanna Syri ◽  
...  
Keyword(s):  
Demand Response ◽  
District Heating ◽  
Heating System ◽  
Hot Water ◽  
Production Costs ◽  
Building Stock ◽  
District Heating System ◽  
Response Control ◽  
Water Storage Tank ◽  
The Impact

Demand response has been studied in district heating connected buildings since the rollout of smart, communicating devices has made it cost-effective to control buildings’ energy consumption externally. This research investigates optimal demand response control strategies from the district heating operator perspective. Based on earlier simulations on the building level, different case algorithms were simulated on a typical district heating system. The results show that even in the best case, heat production costs can be decreased by only 0.7%. However, by implementing hot water thermal storage in the system, demand response can become more profitable, resulting in 1.4% cost savings. It is concluded that the hot water storage tank can balance district heating peak loads for longer periods of time, which enhances the ability to use demand response strategies on a larger share of the building stock.

Exergoeconomic Analysis of District Heating Systems

2009 ◽  
Author(s):  
Vittorio Verda ◽  
Serena Fausone
Keyword(s):  
Fossil Fuels ◽  
Probabilistic Approach ◽  
District Heating ◽  
Heating System ◽  
Primary Energy ◽  
Combined Cycle ◽  
District Heating System ◽  
Heating Systems ◽  
District Heating Systems ◽  
Selection Of

District heating is a rational way to use fossil fuels for domestic heating (and cooling) in towns, especially if it is joined to a cogenerative production of electricity. The aim of this paper is to propose the use of exergoeconomic procedures for the design and analysis of district heating systems. Network design basically involves the selection of the areas to be connected to the network as well as the selection of some design variables as the pipe diameters, the location of pumps etc. This choice is operated assuming primary energy consumption as the objective function to be minimized. The application of these concepts is operated through a probabilistic approach derived from Simulated Annealing. An application to the Turin district heating system is presented here. The system is composed of a cogenerative combined cycle, some auxiliary boilers and the pipe network. An exergetic cost is associated to each user or potential user. This information is used to evaluate the opportunities for future expansions of the served area as well as the variation in some of the operating parameters.

Exergoeconomic analysis of renewable multi-generation system

2020 ◽  
pp. 99-111
Author(s):  
Vontas Alfenny Nahan ◽  
Audrius Bagdanavicius ◽  
Andrew McMullan
Keyword(s):  
Capital Investment ◽  
Combined Cycle ◽  
Asian Countries ◽  
Generation System ◽  
Integrated Gasification Combined Cycle ◽  
Heating And Cooling ◽  
Integrated Gasification ◽  
Exergoeconomic Analysis ◽  
Main Components ◽  
The Cost

In this study a new multi-generation system which generates power (electricity), thermal energy (heating and cooling) and ash for agricultural needs has been developed and analysed. The system consists of a Biomass Integrated Gasification Combined Cycle (BIGCC) and an absorption chiller system. The system generates about 3.4 MW electricity, 4.9 MW of heat, 88 kW of cooling and 90 kg/h of ash. The multi-generation system has been modelled using Cycle Tempo and EES. Energy, exergy and exergoeconomic analysis of this system had been conducted and exergy costs have been calculated. The exergoeconomic study shows that gasifier, combustor, and Heat Recovery Steam Generator are the main components where the total cost rates are the highest. Exergoeconomic variables such as relative cost difference (r) and exergoeconomic factor (f) have also been calculated. Exergoeconomic factor of evaporator, combustor and condenser are 1.3%, 0.7% and 0.9%, respectively, which is considered very low, indicates that the capital cost rates are much lower than the exergy destruction cost rates. It implies that the improvement of these components could be achieved by increasing the capital investment. The exergy cost of electricity produced in the gas turbine and steam turbine is 0.1050 £/kWh and 0.1627 £/kWh, respectively. The cost of ash is 0.0031 £/kg. In some Asian countries, such as Indonesia, ash could be used as fertilizer for agriculture. Heat exergy cost is 0.0619 £/kWh for gasifier and 0.3972 £/kWh for condenser in the BIGCC system. In the AC system, the exergy cost of the heat in the condenser and absorber is about 0.2956 £/kWh and 0.5636 £/kWh, respectively. The exergy cost of cooling in the AC system is 0.4706 £/kWh. This study shows that exergoeconomic analysis is powerful tool for assessing the costs of products.

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