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For example, the non-energy cost of coal-fired power plant is calculated as the sum of overnight capital cost amortized using a capital recovery factor and converted to dollars per unit of energy output by applying a capacity factor , fixed and variable operations and maintenance costs. The second term, fuel or electricity cost, depends on the specified efficiency of the technology, which determines the amount of fuel or electricity required to produce each unit of output, as well as the cost of the fuel or electricity.
The nesting structure of the electric sector is shown in the figure below, with a focus on one repesentative technology.
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Schematic showing the nesting structure of the electric sector, with levels for choices between fuels, technologies, and cooling systems. Details on the assumptions used in GCAM e. GCAM also includes the water inputs to electricity generation, in a third nest, as shown in the figure above. That is, within any thermo-electric generation technology, there is modeled competition between up to five different cooling system types; this is documented in the water section.
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The refining sector, or liquid fuels production sector, explicitly tracks all energy inputs, emissions, and costs involved with converting primary energy forms into liquid fuels. Liquid fuels include gasoline, diesel, kerosene, ethanol and many other liquid hydrocarbon fuels; for the full mapping see Mapping the IEA Energy Balances.
The refining sector includes subsectors of oil refining, biomass liquids, gas to liquids, and coal to liquids, each of which are described below.
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Each of these four subsectors is available starting in the first future time period, and the capital stocks of refineries are explicitly tracked. The structure of refining in the broader energy system is shown in the following figure, with example input-output coefficients. Structure of refining sector and associated products within the energy system, with sample input-output coefficients shown. Electricity and natural gas inputs to oil refining not shown for simplicity.
The oil refining subsector accounts for the vast majority of the historical output of the refining sector, globally and in all regions. Each region is assigned a single production technology for oil refining; as indicated in the figure above, this technology does not differentiate between conventional and unconventional oil, whose competition is explicitly modeled upstream of the refining sector.
In a typical region, the oil refining technology consumes three energy inputs: crude oil, natural gas, and electricity. This is depicted graphically below, with typical input-output coefficients shown. Oil refining production technology, with example coefficients. The coefficients of the oil refining production technology reflect whole-process inputs and liquid fuel outputs; there is no explicit tracking of the production and on-site use of intermediate products such as refinery gas still gas.
The biomass liquids subsector includes up to eight technologies in each region, with a global total of 11, listed in Table 1.
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Starting in , second-generation biofuels cellulosic ethanol and Fischer-Tropsch syn-fuels are introduced, each with three levels of CCS: none, level 1, and level 2. The second CCS level includes a broader set of sources e. Note that the CO 2 emissions intensity is substantially higher than all other liquid fuel production technologies, due to high process energy intensities, and high primary fuel carbon contents.
Where crude oil refining emits about 5. As with biomass liquids, two different production technologies with CCS are represented, with costs and CO 2 removal fractions based on Dooley and Dahowski While a minor contributor to liquid fuels production globally about 0. Gas processing and distribution, with example coefficients. This structure is intended to allow for substitution away from natural gas as the feedstock for the gaseous fuels used by the energy transformation and consumption sectors, as determined by the relative economics.
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The three subsectors of the gas processing sector, and the downstream sectors are described below. The natural gas commodity in GCAM includes all gaseous fuels produced at gas wells, the gaseous co-products from oil production, and gas produced from coal mines and coal seams. The natural gas commodity excludes natural gas liquids, and it excludes gas that is vented, flared, or re-injected. In the gas processing sector, the natural gas technology is assigned an input-output coefficient of 1, as natural gas plant fuel is not a disaggregated flow in the IEA energy balances.
The GCAM coal gasification technology in historical years represents gas works gas, or town gas, that is produced from coal.
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It does not include blast furnace gas, coke oven gas, and other coal-derived gaseous fuels that are by-products of other activities, and typically consumed on-site. Many regions produced no coal gas in In future periods, the technology represents a broader suite of coal gasification processes that are capable of producing a commodity that competes for market share with natural gas.
See Linden et al. In historical years, biomass gasification, or biogas, is considered to be gases captured from landfills, sludge, and agricultural wastes, that are used to provide heat and power. As with coal gasification, in future periods, biomass gasification is intended to represent a suite of processes that convert biomass feedstocks into pipeline-grade gaseous fuels that can be used by a variety of end users.
For a technical description see Zwart et al. The gas pipeline sector explicitly represents the energy consumed by compressors for transmission and distribution of natural gas. Delivered gas and wholesale gas are differentiated in their consumers and therefore cost mark-ups; delivered gas refers to gas used by the buildings and transportation sectors, whereas wholesale gas is used by industrial and energy sector consumers. The historical input-output coefficient of the gas pipeline sector in any region is estimated as the sum of reported pipeline energy consumption, delivered gas, and wholesale gas, divided by the sum of delivered gas and wholesale gas.
john-und.sandra-gaertner.de/silvio-que-levante-la-mano.php Note however that the following sectors consume natural gas upstream of the network shown in the figure above: unconventional oil production, gas-to-liquids refineries, and central hydrogen production. The gas used by these three processes is not assigned the cost mark-ups or upstream pipeline losses assumed in other industrial or energy sector consumers, and there is no capacity for the model to supply the gas used for these purposes with coal- or biomass-derived gas.
Heat is included as a final energy carrier in the IEA Energy Balances, and is intended to represent heat sold to third parties. In most regions in GCAM, heat is not explicitly represented as an energy commodity; instead, the reported fuel inputs to heat plants are assigned directly to the end use sectors that consume the heat buildings and industry.
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Combined heat and power CHP is included as a technology option, but is located within the industrial energy use sector, and no inter-sectoral flow of heat is represented. However, in several regions where purchased heat accounts for a large share of the final energy use, GCAM does include a representation of district heat production, with four competing technology options, shown below. District heating structure, with example input-output coefficients shown.
This is illustrated further in the graphic below. Energy flows in the pulp and paper industries, illustrating the delineation between energy producers and energy consumers. Source: IEA In regions where heat is modeled as an energy commodity, the heat output of these main activity CHP plants is treated as a secondary output, and added to the total district heat produced in the given region. In future years, any new installations in the power sector are not assigned this secondary output of district heat; over time, these two sectors are modeled separately. Hydrogen in GCAM is modeled purely as a future energy commodity; while industrial scale volumes of hydrogen are currently produced e.
As such, the use of hydrogen as an energy carrier is assumed zero in the base years of GCAM, and starting in it is allowed to compete for market share supplying heat and power in the industrial sector, and for vehicle fuel in the transportation sector.
The representation of hydrogen in GCAM includes 10 production technologies in two production sectors, with cost mark-ups to reflect levelized infrastructural costs, as well as variable transmission and distribution costs. The structure of the hydrogen production and distribution sectors and technologies in GCAM generally uses the structure of the U. Hydrogen structure, with example input-output coefficients shown.
As in the H2A model, the production of hydrogen takes place in two distinct sectors: H 2 Forecourt Production i. The hydrogen produced at central facilities incurs additional cost mark-ups to reflect the distribution costs, whereas forecourt production typically entails higher energy intensities on the production side, and higher per-unit costs.
Central production also has a greater diversity of feedstock options, described below. The most common hydrogen production technology today is natural gas steam reforming, though coal chemical transformation is the dominant technology in China IEA In GCAM, all regions have access to all technologies when hydrogen as an energy carrier becomes available; as shown in the figure above, hydrogen can be produced from up to 7 primary energy sources. Three of these sources coal, gas, and biomass include production technologies with CCS, characterized by higher costs and higher energy intensities, but lower CO 2 emissions.
The wind and solar technologies are electrolysis technologies, but are specifically disaggregated because these uses of wind and solar energy do not incur any backup-related costs, unlike in the electricity sector where backup costs increase as a function of their share of total grid capacity see electricity. In contrast, the nuclear technology represents thermal splitting, which does not use electricity as an intermediate energy product. GCAM disaggregates the building sector into residential and commercial sectors and models three aggregate services heating, cooling, and other.
Within each region, each type of building and each service starts with a different mix of fuels supplying energy see Figure below. The future evolution of building energy use is shaped by changes in 1 floorspace, 2 the level of building service per unit of floorspace, and 3 fuel and technology choices by consumers. Floorspace depends on population, income, and exogenously specified satiation levels. The level of building service demands per unit of floorspace depend on climate, building shell conductivity, income, and satiation levels. The approach used in the buildings sector is documented in Clarke et al.
The following section summarizes the functional forms linking regional socioeconomic conditions, exogenous assumptions about the buildings sector e. The demand for per-capita floorspace, f , in future time period t is shown below. The demands of generic services per unit floorspace, d , are shown in the equation below:. Space heating h and cooling c services use a similar approach with some additional considerations, shown below:.
Related Energy Balances of non-OECD Countries 2012
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