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170 H. Safaei et al. / Applied Energy 103 (2013) 165–179 between the heat load and the geological formation for storage of compressed air. 2.2.4. Wind resources Hourly generation data from existing wind farms in Alberta re- ported by AESO [26] for the period of 2008–2011 were used in this study. The hourly capacity factor of wind (ratio of the hourly gen- eration to the name plate capacity of the wind farm) was calcu- lated to represent the quality of wind resources to be exploited for electricity generation during the simulation period. 2.2.5. Compressed air pipeline A pipeline is required to transport the generated compressed air from the compressor/heat-load site to the underground storage facility. The economics of DCAES are strongly dependent on the capital cost of the pipeline. A pipeline length of 50 km was used in the base case system and the sensitivity of the results to this va- lue was then performed through running the simulation with 25 and 100 km lengths for the air pipeline. Furthermore, an unrealistic scenario with a pipeline length of 0 km is considered to provide better insight into the tradeoff between the capital cost of the pipe- line and revenues generated from waste heat recovery. One should note that this study focuses on Calgary, Alberta as a case study. Cal- gary is in close proximity of depleted gas reservoirs that could be used for underground storage of compressed air. Due to the relatively short length of the pipeline (50 km) and to maximize waste heat recovery benefits in the DCAES configuration, no boosting compression stations were considered. In other words, the maximum downstream pressure of the pipeline was fixed (equal to the maximum cavern pressure, 74 bar) and the upstream compression facility was sized to be able to compensate for the pressure drop along the pipeline. At the same time, the upstream pressure was set to a value lower than the Maximum Allowable Operating Pressure (MAOP) of the pipeline (set as 100 bar). Eq. (1) relates the flow rate of the compressed air to the pipe diameter and length and the upstream and downstream pressures (see nomenclature for definition of symbols) [27]. 2 2 4 TLZfQ2 PUpPDown 1⁄49:3610 D5 ð1Þ The maximum allowable pressure drop along the compressed air pipeline was set to 35 kPa per km, a typical value for natural gas pipelines [28]. By fixing downstream pressure (PDown) and knowing the maximum air flow rate in the pipeline given compres- sor size, Eq. (1) was used to calculate the pipe diameter. Once the pipe diameter was determined, its length and diameter were used to estimate the capital cost of the pipeline based on regression models for industrial pipelines [29]. 2.2.6. Storage facility Compressed air energy storage facilities can use both above- and underground storage [30–32]. Both high pressure storage tanks and pipelines can be utilized in aboveground CAES systems; however, aboveground CAES systems are not economically feasible for utility scale (bulk) storage due to the significantly higher capital costs associated with aboveground compared to underground stor- age [10]. Underground CAES can utilize a variety of geological for- mations (naturally formed or man-made salt caverns, hard rock and porous rock formations, and depleted gas reservoirs) to store compressed air in large quantities [11]. The selection of the proper formation is subject to various factors such as its availability, geo- logical characteristics, and development costs. Porous rock forma- tions were considered as the storage for this study since Calgary is in the proximity of porous rock geological formations. As explained in the previous section, this formation was assumed to be located at a distance of 50 km from the heat load (equal to the length of the air pipeline) in the base case analysis. 2.2.7. Operation of CAES and DCAES A compressed air storage facility is very similar to a conven- tional gas turbine power plant with the major difference that the air compression and expansion processes do not happen at the same time. However, in principle a CAES plant can run as a simple cycle gas turbine during the periods that the cavern is depleted [12]. This capability was considered in the optimization model such that the expander could receive compressed air required for its operation from both the cavern (running as a pure CAES) and the compressor (running as a pure SCGT). 2.2.8. Fuel price A series of recent studies [12,22,23] have shown that the capital intensive conventional CAES facilities would not be economically favorable over conventional gas turbines to support wind-based electricity under the current low natural gas prices (as the primary fuel for CAES and gas turbine plants). However, CAES would be- come superior in a carbon-constrained world due to its lower emissions compared to conventional gas turbines. Therefore, a var- iable emission tax is considered in the natural gas price in this study and the effective fuel price (combination of market price of the natural gas, fixed at $5.0/GJ,2 and associated emission taxes) was calculated based on Eq. (2). The effective fuel price concept incorporates both the fluctuations in the market price of fuel and the associated emission taxes due to the GHG emissions from the combustion of the fuel. A value of 66 kg CO2e3/GJ was considered as GHG emissions associated with burning natural gas (including the typical4 upstream emissions) [23]. As a case in point, a market price of $5.0/GJ for natural gas and an emission tax of $30/tCO2e5 would translate to an effective natural gas price of $7.0/GJ. At low levels of tax, neither a CAES nor a DCAES system is expected to be superior to gas turbines. However, as the effective fuel price in- creases, CAES becomes more favorable and finally at higher effective fuel prices, a DCAES system is expected to become superior. PriceEff 1⁄4 PriceMarket þ Tax GHGNG ð2Þ NG NG 2.2.9. Capital cost Table 1 illustrates the inputs used in evaluating the associated cost of various components of the two systems. All costs were con- verted to 2009 inflation adjusted US dollars according to the Chem- ical Engineering Plant Cost Index [33,34]. The capital cost of the heat recovery unit was assumed negligible since this heat has to be removed during inter-stage cooling between compression stages and from the compressed air prior to underground storage anyways (whether it is utilized for heating applications or dumped to the ambient). Similarly, the associated capital costs with the dis- trict heating network (excluding the boilers) were ignored in the analysis since this network would exist in both CAES and DCAES configurations. In other words, the district heating system would be utilized to satisfy the heat load, regardless the source of the heating energy (HOB or HRU). One should note that recovering the heat of compression would shave the peak heating load and 2 All heating values in this paper are expressed in terms of lower heating value (LHV). Higher heating value (HHV) energy content of natural gas is about 11% higher than its LHV. Therefore, a natural gas price of $5.0/GJ (LHV) corresponds to approximately $4.5/GJ (HHV). 3 Greenhouse gas emissions are expressed in equivalent amounts of carbon dioxide (CO2e) in this paper. 4 The GHG emissions associated with manufacturing of the components were not included. 5 One t indicates one metric ton (1000 kg).PDF Image | 20 kW ORC Turbine Off-Design Performance Analysis
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