Energy Hub Based on Nuclear Energy and ... - ACS Publications

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Energy Hub Based on Nuclear Energy and Hydrogen Energy Storage Yaser Maniyali,† Ali Almansoori,*,‡ Michael Fowler,† and Ali Elkamel† †

Chemical Engineering Department, University of Waterloo, Waterloo, Ontario, Canada N2L 3G1 Department of Chemical Engineering, The Petroleum Institute, P.O. Box 2533, Abu Dhabi, UAE

‡

ABSTRACT: An ‘energy hub’ comprises of the interactions of different energy loads and sources for power generation, storage, and conversion. This paper presents an energy hub consisting of nuclear plants, wind turbines, solar panels, biomass reactors, electrolyzers, and fuel cells. The hub serves to replace existing coal-based power generating facilities to meet electricity and hydrogen demands for industrial and transportation sectors, as projected in 2030. Equipment sizing and costing analysis for different energy production technologies and hydrogen storage were considered using Matlab/Simulink. Several energy hub designs with various technological combinations were analyzed, and a profitability analysis was conducted to evaluate the feasibility of each energy hub. The proposed models also evaluate the environmental benefits of the future energy hub and outline the best hub configurations. It was found that the most economical energy hub is when nuclear reactor was operated throughout the year at a capacity near to the grid’s average annual electricity demand. Underground hydrogen storage emerged as the most economical option for all hubs analyzed, and any excess power was converted to hydrogen for sale in the industrial and transportation sectors.

1. INTRODUCTION There is a need to address the risks to human health posed by urban pollution and to reduce dependence on fossil fuels to address climate change. This has led to an upsurge in the focus for future power on nuclear and renewable energy sources. Renewable energy sources, particularly wind and solar, due to their intermittent nature, are distributed over a large area of land, which can be utilized for various purposes. Since wind and solar energy are both intermittent sources, electricity supply and demand periods are often not synchronized, and upgrades in the electrical distributing system are required. Consequently, back-up power or another form of power storage system is needed to fully take advantage of renewable energy sources.1,2 Nuclear power can be employed to resolve this issue. It is also another key option available for alleviating the risk of global climate change and its potential contribution to greenhouse gas emissions. Combining these three major sources of energy together with some energy storage capacity in the form of an ‘energy hub’ allows optimal use of all available energy resources. An energy hub can be defined as the interaction of energy loads and energy sources which include different technologies for power generation, energy storage, and energy conversion.3−5 These technologies could include transformers, wind turbines, electrolyzers, solar panels, and fuel cells. Hydrogen is an ideal energy vector for use in energy hubs where energy can be produced from multiple energy sources like nuclear power and renewable energy. Once hydrogen is produced, it can be used to power propulsion systems, such as light duty vehicles, or sold as a commodity for power generation or industrial applications.6 The concept of a hydrogen economy has attracted a great deal of attention in industries and academia as it holds the promise of a sustainable energy distribution system. It is an integrated energy system based on hydrogen, which enables the widespread integration of renewable energy sources such as wind and solar power.7 The use of hydrogen would allow the © XXXX American Chemical Society

storage of electricity until it is needed to match demand or the supply of hydrogen for transportation. The conversion of electricity to hydrogen can be achieved today in a clean manner through electrolysis, which produces zero greenhouse gases or other pollutants. Although currently over 95% of hydrogen is obtained from natural gas through steam methane reforming, the use of electrolysis and future technologies such as Cu−Cl thermochemical cycles with nuclear reactors have the potential to replace existing generation techniques for large scale production.8 From the perspective of centralized energy generation, hydrogen can be used to store excess electricity generated from other energy sources during periods of low electricity demand using electrolyzers. The stored hydrogen can then be converted back to electricity to meet peak electricity demand using fuel cells. It can also be commercially sold for other industrial and chemical purposes. Another interesting possibility of the future hydrogen economy lies in the context of competitive electricity markets, given the significant price differences between peak and low cost hours, which may or may not necessarily coincide with peak and low demand hours. In addition, where there are technical limitations in electricity distribution such as transmission congestion, the use of hydrogen as an energy carrier to increase the efficiency and reliability of the electric grid becomes an attractive option. Hydrogen in transportation applications, especially light duty vehicles and rail, can be an onboard fuel that provides rapid refueling, high reliability, zero emissions, and high conversion efficiency. There are several reasons behind the government of Ontario’s decision to move away from coal as a source of Received: August 10, 2012 Revised: April 22, 2013 Accepted: May 13, 2013

A

dx.doi.org/10.1021/ie302161n | Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

Industrial & Engineering Chemistry Research

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resources such as solar, and wind, and be able to store energy in the form of hydrogen and convert hydrogen back to electricity when demand returns. Also, the hub can facilitate the demand for vehicles running on hydrogen, and it will be able to significantly reduce costs per megawatt (MW) of power generated compared to decentralized systems where costs per MW of power generation and distribution are higher.15 Therefore, in this study, a conceptual clean energy hub consisting of wind, solar, nuclear, and biomass technologies is analyzed. In order to simulate potential electricity demand profiles for the hub, the hourly electricity demand profiles and transmission constraints were obtained for an existing coal power plant that provides for peak electricity demand of 3750 MW. The proposed energy hub will replace the existing coalpower generation facility to meet peak electricity demand of 3750 MW. The hub will also be utilized to meet the demands of the growing hydrogen economy by 2030. Electrolyzers, fuel cells, and hydrogen storage systems are used to facilitate the differences between electricity supply and demand. Three different energy scenarios will be evaluated to determine the best technology mix using technical and economic considerations. The next section summarizes briefly the different components of the proposed energy system (i.e., hub). This includes energy generation technologies, storage options, and conversion and distribution technologies. A description of the future energy hub configuration and the projected electricity demand profile will also be discussed.

electricity. Recent advances in recognizing CO2 as a contributor to climate change have resulted in development of regulations toward a carbon cap and trade system. Such a system will increase the cost per MWh of electricity generation from fossil fuels. Furthermore, various health-related costs can be recognized as a result of air pollutants released from fossil fuels. These health costs can be avoided by obtaining hydrogen from clean energy sources. Such a system will play a key role in CO2 abatement, thereby reducing current expenses on the capture and storage of CO2 and the use of remedial measures to reverse damage to the environment. Therefore, such an integrated energy system could prove to be economically and environmentally viable. Several energy hubs using hydrogen for energy storage have been analyzed to meet grid electricity demand. When optimal operation of hydrogen storage with intermittent renewable energy sources was analyzed in European utility markets, the results obtained suggest that the use of hydrogen significantly increases the hub’s profitability. Sale of oxygen and use of heat produced during electrolyzer operation could further enhance the hub’s profitability.9 Another study indicates that cogeneration of hydrogen and electricity by integrating nuclear plants, and wind turbines, with electrolyzers further enhances profitability of the hub with hydrogen costing approximately $2 per kg.10 Forsberg11 demonstrates the ability to combine nuclear reactors with biomass to produce liquid fuels for transportation in a proposed Hydrogen Intermediate and Peak Electrical System. In this analysis, fuel cells with nuclear reactors and an underground hydrogen storage system takes advantage of storing electrical energy during off-peak hours and selling the electricity during peak hours.12 In addition, hydrogen can also be distributed as a fuel for transportation systems which provide premium revenues for hydrogen ($100−125 per MWh as opposed to $55 per MWh for utilities), when compared to equivalent prices for usable energy obtained from gasoline. A previous study13 had been conducted to develop mathematical models to optimize energy production for oil sands operations. The study aimed to minimize the total annual cost of supplying energy to the oil sands industry, taking into account CO2 emission constraints. Such Energy Optimization Models determine optimal combinations of power and hydrogen plants that satisfy given energy demands of oil sands operations, at minimal cost and with reduced CO2 emissions. Since the energy is supplied by a variety of sources such as electric power, hydrogen, steam, hot water, diesel, and process fuel, such models are very similar to the model developed in this paper. The difference is that in this paper, wind, solar, biomass, and nuclear energy have also been incorporated into the models for the different scenarios and that hydrogen has been used as an energy vector which can be produced from multiple energy sources, such as nuclear power and renewable energy, rather than from hydrogen plants. Due to the environmental effects of operating coal-fired plants, the Ontario government has passed a regulation phasing out the use of coal power generation at existing facilities by end of year 2014.14 This provides a unique opportunity to utilize the existing transmission lines to create a centralized powergeneration hub comprising of renewable, nuclear, and biomass energy with hydrogen as the energy vector. Such a hub would have several distinct advantages. It will significantly reduce environmental emissions compared to the existing coal plant. It will be able to facilitate the intermittency of renewable

2. ENERGY GENERATION TECHNOLOGIES 2.1. Wind Energy. The wind profile for the energy hub is determined by selecting the best suited turbine model that accounts for geographical changes in wind.16,17 Therefore, offshore and onshore wind developments for selection of appropriate turbines, and the number of each of these turbines required are considered for maximizing the wind energy potential. In Ontario, where the coal plant used in this model for analyzing power demand profiles is located, there are a number of wind power projects in various stages of development. Based on IPR Canada’s Web site,18 approximately a 300 MW of offshore wind power is under development within 100 km (km) of the current coal plant, which would significantly increase the amount of wind power in Ontario as whole. For the conceptual design of this energy hub, this study makes use of both onshore and offshore wind turbines based on a preliminary comparison with existing projects and those in the planning stage. 2.2. Solar Energy. Solar energy collects energy from sunlight either in the form of thermal energy or photo energy. While thermal energy is more suitable for warmer regions, such as the Middle East, photovoltaic (PV) cells prove to be more feasible for colder regions, such as Ontario, Canada, which does have suitable solar levels. PV cells generate electric power when illuminated by sunlight or artificial light. It was found that single crystal silicon cells and polycrystalline silicon cells are the only commercially viable PV technologies suitable for large scale power generation.19,20 Hence, these will be the options considered for the hub design. To design a PV system, the cells should be connected together into modules (arrays of cells) to provide appropriate current and voltage levels. The effect of other environmental factors such as temperature should also be taken in to consideration. For example, the module voltage reduces with increasing temperature, and B



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Figure 1. Projected electricity demand profile in Ontario, Canada.29

location are Generation III reactors which are safer, more efficient, and easier to build than earlier-generation reactors. The three reactors that were considered are as follows: ACR1000 designed by AECL, AP1000 designed by GE-Westinghouse, and EPR-1600 designed by AREVA. These reactors are the most efficient Pressurized Water Reactors currently available and claim to sustain an average availability factor greater than 94% during the entire service life of the plant, obtained through longer fuel cycles, shorter refuelling outages, and in-operation maintenance. All of the reactors are capable of using mixed oxides, which allows for the reactor’s consumed fuel to be recycled and reused.

although current increases slightly, the overall effect is for the efficiency to reduce as temperature increases. This increase is about 0.4−0.5% of their net energy output per °C increase for typical crystalline silicon cells.20 2.3. Biomass Energy. Biomass refers to the totality of biological material that is used globally to generate energy. Wood waste was considered for this study as it was a policy option at the time for the Ontario government. A life cycle analysis assessment of wood pellet use in Nanticoke and Atikokan generating stations done at University of Toronto estimates that roughly 1.25 million ‘Oven Dry Tonnes’ of wood pellet supply is available from Crown forests for the two generating stations combined.21 However, in practice shipping to the current plant location would be an issue, and this model does not fully account for shipping impacts and cost. There is an ongoing requirement for landfill disposal for in the Greater Toronto region and other communities in Southern Ontario. Converting the Municipal Solid Waste in Toronto to Refuse Derived Fuel (RDF) and sending it to the current plant location will help Toronto dispose its refuse while allowing for power generation. Biomass using RDF emits less greenhouse gases, NOx, and SOx emissions than that from coal. The benefit of biomass lies in the fact that growing vegetation will reabsorb the CO2 released during combustion. It also fits well with the current plant location’s existing bioinfrastructure with excellent shipping and rail access which provides an alternative carbon neutral energy generation method. Such an option provides power generation flexibility and can be used for peak electricity generation. The continuation of cofiring of coal and biomass facilities at limited times in the year and at peak demand periods would certainly represent a realistic scenario at the energy hub location; hence this is considered in the analysis. 2.4. Nuclear Energy. Nuclear power provides a reliable, stable, and greenhouse gas free supply of electricity to the energy hub in an efficient and economic manner. As a result, it is the preferred base load source of power for energy hubs.22 The reactors considered for current plant location/energy hub

3. ENERGY STORAGE OPTIONS In order to harness power from intermittent renewable sources, it is imperative to have a low cost energy storage option. For instance, hydrogen storage was considered to be particularly useful for the storage of wind energy which is often greater at night than in the day, unlike electrical demand. The two types of hydrogen storage that were taken into account for the clean energy hub are as follows: aboveground storage tanks and underground storage. Studies23,24 indicate that storage in high pressure tanks would be the most viable aboveground storage option due to technological maturity. As for underground storage, findings25 suggested that salt caverns are the best choice due to their ability to seal most of the injected gas without leakage. However, this region of Ontario does have significant underground natural gas storage infrastructure and storage with natural gas system is an emerging option. Storage with the current natural gas infrastructure has been left for future analysis. In this study, salt caverns which are available in this region have the added advantage of possessing walls with structural strengths of steel that retard reservoir degradation. 4. ENERGY CONVERSION TECHNOLOGIES 4.1. Electrolysis. The conversion of electricity to hydrogen can be achieved today in a clean manner through electrolysis, which produces no operational greenhouse gases or other air C



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Figure 2. Schematic of the proposed energy hub.

Table 1. Energy Supply, Transportation, and Demand Options Considered for the Energy Hub parameters energy source

transformation and transportation H2 distribution potential demand

renewable wind offshore electrical grid existing pipelines electrical regional population growth

nuclear onshore

new

current grid 4000 MW coal

solar PV cells

biomass organic waste energy crops

H2 options electrolysis high temperature electrolysis rail truck hydrogen demand regional future hydrogen economy industrial chemical rail industrial invehicle plants house forklifts regional demo fleet

distributed supply peak electricity generation using PEM fuel cells Ontario vehicle demand

electricity demand for the hub. This is mainly because fuel cells have high hydrogen to electricity energy conversion efficiency ranging between 40−60%.28 The flexibility of design to suit power system, lower air emissions, ease of refuelling, and high reliability are also added advantages.28 It is expected that by the time the hub has been constructed, costs and durability issues would have been overcome. Although a number of different fuel cell technologies were considered, PEM fuel cell technology has clear advantages as it meets the temperature and fuel characteristics required for the energy hub’s operation and is useful in scaling operations and maintenance planning.

pollutants. There are three principal types of water electrolyzers: alkaline (referring to the nature of its liquid electrolyte), Polymer Electrolyte Membrane (PEM) (referring to its solid polymeric electrolyte), and solid-oxide (referring to its solid ceramic electrolyte). While, the PEM electrolyzer is particularly well suited to highly distributed applications, the alkaline electrolyzer currently dominates the global production of electrolytic hydrogen.26 Alkaline electrolyzers emerged as the best option for the proposed model because the energy hub in this study requires large scale production of hydrogen. This could only be ensured by the use of alkaline electrolyzers as both PEM and solid-oxide are still in the development phase27 but could be viable options in the near future. 4.2. Fuel Cells. Critical to the hydrogen economy is the ability to transform hydrogen into electricity. Fuel cells were chosen as the electricity generation method to meet peak

5. ELECTRICITY DEMAND PROFILE There is a need for a sustainable source of energy to meet the projected growth in electricity demand over the next 30 years in D



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Ontario, as shown in Figure 1.29 It can be depicted from Figure 1 that most existing nuclear reactors will either have to be refurbished or replaced by the year 2020. Based on data provided by the Ontario Ministry of Energy in 2008, although there are plans to refurbish and add more nuclear reactors, roughly 15,300 MW of future power generation is expected to come from renewables, of which roughly 6,500 MW of power will be saved by power conservation.29 As a result, new projects will need to be initiated. Hence, making use of the existing transition infrastructure at the energy hub location and replacing the pollution-causing coal plant with a clean energy hub is highly desirable.

convert onshore power output to offshore power output as offshore wind speeds are generally higher and hence produce more power. μT is the step-up transformer efficiency, and INOST and INOFST refer to the number of onshore and offshore wind turbines. The cost of wind energy for hour, i, is calculated as CiWIND = (PiONST × OM ONST + I NONST × CC ONST ) + (PiOFST × OM OFST + I NOFST × CC OFST )

where POFST and PONST represent power generated by offshore i i and onshore wind turbines for hour, i. The former was obtained by using μONOF to convert onshore power output to offshore power output. The latter which represents the onshore power output was obtained through the Independent Electricity System Operator (IESO) for existing wind farms located less than 100 km from the energy hub location. OMONST and OMOFST are the operation and maintenance costs per MW for the onshore and offshore wind turbines, respectively. CCONST and CCOFST refer to capital costs for each onshore and offshore wind turbine. 7.2. Solar Model. The power generated by solar panels for hour, i, is calculated by

6. MODEL STRUCTURE The energy hub model, designed to supply and meet energy needs at the energy hub location, was developed using Matlab/ Simulink. A schematic of the proposed hub structure is shown in Figure 2. The clean energy sources used are either transformed into hydrogen or electricity at the energy hub location. As Figure 2 suggests, the energy sources examined are zero emissions sources such as wind, solar, and nuclear. A limited amount of carbon neutral biomass is also considered. Wind turbines, nuclear reactors, solar photovoltaic cells, and biomass reactors are used as the electricity generation technologies, and electrolyzers are used to convert any excess power to hydrogen. The hydrogen produced is stored primarily in tanks; however, when excess amounts are produced, underground storage is employed. During peak electricity demand periods, fuel cells are used to convert the stored hydrogen to electricity. Table 1 outlines possible supply, transportation, and demand options for the hydrogen and electricity produced. Energy is supplied through various renewable sources and nuclear reactors. The generated electricity is distributed through the existing or new power grid; whereas hydrogen is transported via pipelines, rail, or tanker trucks. The electricity generated is used to meet demands for the energy hub location’s grid and plug-in hybrid vehicles, whereas hydrogen is mainly required by chemical industries and the transportation sector for hydrogen cars, rail, and hydrogen-run forklifts.

PiSUN = (DTSUN × D ISUN × I ASUN × μSUN × μ INV × μT ) (3) TSUN

where D and D represent respectively the hourly temperature and insolation data for the energy hub location. IASUN refers to the total area of solar panels, μT, μSUN, and μINV are the efficiency factors of the step-up transformer, solar PV cells, and DC/AC inverter, respectively. The cost of solar energy for hour, i, is given by SUN CiSUN = Pmax × (OMi SUN + C INVSUN )

+ (I NPV × I MROW × CC mod)

(4)

PSUN max

where represents the maximum power generated by the solar PEM cells, OMSUN is the operating and maintenance cost i for solar panels for hour, i, and INPV and IMROW are the number of PV rows and modules per row, respectively. CINVSUN stands for inverter costs for solar panels, and CCMOD corresponds to capital costs for each solar module. 7.3. Nuclear Model. The nuclear reactor chosen is ACR1000. This type of reactor was selected over its counterpart CANDU reactors due to its ability to conserve power output during times of low electricity demand.31 It also has superior load-following characteristics. However, due to unavailability of its load-following characteristics, a CANDU 6 plant was used to estimate the power output for hour, i, as follows:

7. MODEL FORMULATION The following section discusses how the model estimates the following: (1) the total power generated by the hub, (2) the amount of hydrogen stored in the underground facility, (3) the amount of emissions averted, and (4) the total annual revenue generated by the hub. These estimates are used to assess the feasibility of the proposed energy hub. For the sake of ease of referencing, all the parameters used in the development of the model are summarized in the Notation Section (i.e., Model Notations).30 7.1. Wind Model. The power generated by the wind model for hour, i, can be calculated by

NUKE PiNUKE = (Pmax × CjNOPT )

(5)

PNUKE max

is the maximum nuclear capacity; however, in practice, the units are operated between 60 and 100% of full capacity. The reactors are operated at 60% during periods of low electricity demand as storing excess hydrogen in tanks is costintensive. Nevertheless, when hydrogen is stored underground, reactors are run at full capacity to supply to industries and the transportation sector. The daily electricity demand profile at the energy hub location can be divided into four distinct 6-h periods. CNOPT j refers to the run factor of the nuclear reactor for every 6 h of the day (4 a.m./p.m. and 10 a.m./p.m.), which is represented

ONST × I NONST ) PiWIND = (DiOST × Pmax OFST + (DiOST × μONOF × Pmax × I NOFST ) × μT

ISUN

(1)

PWIND i

where is the power generated by the onshore and offshore wind turbines for hour, i. DOST is the hourly onshore i OFST wind data for the energy hub location, and PONST max and Pmax are the maximum power of each onshore and offshore wind turbine. In eq 1, μONOF represents the onshore to offshore convertor, and its value varies seasonally. μONOF is used to E



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by j and is calculated based on the supply demand for power over the last two hours. The nuclear energy’s total cost for hour, i, is given by

include costs for recoating, rebuilding, refurbishing, or replacing electrolyzers. 7.6. Fuel Cell Model. Power produced by fuel cells is obtained from

NUKE CiNUKE = [(Pmax × CC NUKE) + (PiNUKE × OM NUKE)]

PiFC = CiFCNUM × μT

(6)

CCNUKE signifies capital cost per MW reactor capacity, and OMNUKE stands for operation and maintenance costs per MW power generated. In Canada, where the energy hub location is modeled, the Canadian Nuclear Safety Commission (CNSC) is responsible for regulating nuclear waste disposal and reactor safety among other areas. Since all nuclear power generation facilities in Canada need to comply with regulations set forth by CNSC, it is assumed that the compliance costs are included in the operation and maintenance costs for the nuclear facility. 7.4. Biomass Model. The two main fuels for biomass are RDF and Woody Biomass. Additional coal boilers are used only to meet demands during peak periods. The total energy produced for hour, i, can be calculated as

where is the varying fuel cell number, based on the supply demand power data for hour, i. The cost of using fuel cells for hour, i, is calculated as STKFC FC CiFC = [(αi FCON × Pmax × Nmax × CC FC)

+ (PiFC × OM FC)]

is a binary variable that indicates if the fuel cell is in operation or not (0 if off or 1 if on). PSTKFC is the maximum max power in MW per stack of fuel cells, and NFC max is the maximum number of fuel cells determined by the model using energy supply demand data. Since the maximum number of electrolyzers was bounded between 100−500, the number of fuel cell stacks is unbounded to ensure that the power demands are met. CCFC and OMFC indicate capital and fixed costs and operation and maintenance costs for the cells, respectively. 7.7. Hydrogen Storage. The amount of hydrogen (in kg) stored for hour i, is given by

WOOD + (I NWOOD × Pmax × CjRWOPT )

NRDF

NWOOD

(7)

NCOAL

where I ,I , and I refer to the number of RDF, woody biomass, and coal boilers, respectively. CRWOPT is the j RDF and woody biomass boiler run factor for every 6 h of the day (4 a.m./p.m. and 10 a.m./p.m.), which is represented again by j; whereas CCOALOPT is the coal boiler run factor for hour, i. j These run factors take into account the fact that biomass reactors are expected to be run only during peak demand WOOD COAL periods. PRDF max , Pmax , and Pmax represent the maximum power capacity of the RDF, woody, and coal boilers, respectively. 300MW is used for the coal boiler’s capacity to keep emissions to a minimum while satisfying peak demand requirements. The total cost of biomass energy for hour, i, is

ELEC ViHY = [ViHY × c ELECHY ) − (PiFC × c FCHY )] − 1 + (Pi

(13) ELECHY

PWOOD , I

PRDF , i

CiSTG = [ViHY × (LUEC STG + LUEC CPR )] STG

(8)

PCOAL i

=

[CiELECOPT

×

ELEC Imax

COMP

×μ

×μ

INV

TSD

×μ

(14)

CPR

LUEC and LUEC denote the levelized unit energy cost per kg of hydrogen stored underground and the levelized unit energy cost for compressor per kg of hydrogen stored in aboveground tanks. 7.8. Total Generated Power. The total power generated by the energy hub for hour, i, is obtained as

and correspond to power generated by the woody biomass, RDF, and coal boilers for hour, i, respectively. LUECWOOD, LUECRDF, and LUECCOAL stand for levelized unit energy cost per MW of power produced by woody biomass, RDF, and coal boilers. 7.5. Electrolyzer Model. The total power generated by electrolyzer technologies for hour, i, is given by PiELEC

FCHY

where c and c are the amounts of hydrogen (in kg) obtained per 1 MWh from electrolyzers and fuel cells, respectively. The cost of storing hydrogen for hour, i, is given by

CiBIO = [(PiWOOD × LUECWOOD) + (PiRDF × LUEC RDF ) + (PiCOAL × LUEC COAL)]

(12)

αFCON i

RDF PiBIO = [(I NRDF × Pmax × CjRWOPT )

COAL + (I NCOAL × Pmax × CiCOALOPT )]

(11)

CFCNUM i

PiTOT = PiWIND + PiNUKE + PiSUN + PiBIO − PiELEC + PiFC (15)

The total cost of the energy hub for a yearly operation of 8760 h can be calculated by 8760 TOT

C

=

∑ (CiWIND + CiSUN + CiNUKE + CiBIO + CiELEC i=1

]

+ CiFC + CiSTG)

(9)

where IELEC max refers to the maximum number of electrolyzers, which is typically capped at 100 or 500. CELECOPT is the i electrolyzer run factor for hour, i, and μCOMP and μTSD are the compressor and step-down transformer efficiency, respectively. The cost of using electrolyzers for hour, i, was estimated as follows

(16)

7.9. Emissions Reduction. The model estimates the total emissions reduced by the hub as follows: 8760 TOT

E

= (∑

8760

PiTOT

×E

COAL

) + ( ∑ ViIND × E NAT )

i=1 8760

ELEC CiELEC = [Imax × (CC ELEC + OM ELEC + REP ELEC)]

i=1 8760

+ ( ∑ ViTRN × EGAS) − ( ∑ PiWOOD × EWOOD)

(10)

i=1 8760

where CCELEC, OMELEC, and REPELEC stand for capital, operation, and maintenance costs, and possible repair costs for each electrolyzer, respectively. These repair costs may

− ( ∑ PiRDF × E RDF ) i=1

F

i=1

(17)



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ENAT denotes emissions in kg per kg hydrogen generated from natural gas plants, and EGAS denotes equivalent gasoline emissions in kg per kg hydrogen used. EWOOD,ECOAL, and ERDF are emissions in kg per MW of power produced by woody biomass, coal, and RDF boilers, respectively. VIND and VTRN i i represent the amounts of hydrogen in kg used for the industry and transportation for hour, i. The model attempts to assign a tangible value to show the benefits of the emissions reduction by assigning prices for each type of emission. This is done by the following equation R

ETOT

TOT

=E

+P CO2

× (P

SOx

CO

CO2

+P

NOx

+P

VOC SOx

CO

+P

+P

PM

the electricity demand from plug-in hybrid electric vehicles (PHEV). Given Ontario’s generation mix, especially after coal plants are phased-out, migrating to electric vehicles in the transportation sector made overall economic and environmental sense in the long term [25]. The following formula was used to estimate the demand for PHEV in MW if an 8-h continuous supply period from 10 p.m.−6 a.m. exists P PHEV = (N c × PGTA × F PH × N KL × E EL × F E × PConv) /(P c × N RC × N H )

NOx

+P

HM

VOC

)

where NC, NKL, NRC, and NH represent the number of light vehicles in Canada, number of kilometers run by an average car in Greater Toronto Area (GTA), the number of nights vehicles are recharged, and the number of hours electricity would be supplied (8-h period), respectively. FPH indicates the expected fraction of PHEV in Ontario by 2020, and FE stands for the electricity fraction supplied to GTA by the energy hub. PGTA and PC denote the population of GTA and Canada, respectively; while EEL is the electrical energy needed to propel a vehicle for 100 km, and PConv is the conversion factor from megajoules (MJ) to megawatt-hour (MWh). Table 2 summarizes the parameters used in our calculations.

(18)

PM

where P , P , P , P , P , and P represent price per kg of CO2, NOx, SOx, volatile organic compounds, and particulate matter emissions, respectively. PHM represents price per kg of heavy metals. The price of CO2 is assumed at $27.5 per tonne since the US government is planning on creating a carbon trading market with prices ranging from $16−33 per tonne of CO2 by 2020.32 However, this may be a very conservative assumption according to other studies and predictions. 7.10. Revenue Generated. The total revenue for each energy source for the entire year is calculated by this formula 8760

Table 2. Summary of Parameters for Estimating Electricity Demand

8760

SRC R tot = [ ∑ (PiSRC × DiHOEP ) × i=1

∑ αiONOFF ] i=1

(23)

(19)

where PSRC is the power generated by each energy source for i hour, i. SRC represents energy sources such as wind, solar, nuclear, biomass, or fuel cell. DHOEP is the data for the hourly i Ontario energy price, which lists the price of electricity paid by the public for hour, i. αONOFF is used to find the total hours a i specific energy source operated for the year. It can have two values: 0 when the source is off or 1 when it is on. The revenue from selling hydrogen is calculated as follows

parameter

unit

number of light vehicles in Canada33 estimated population of Canada34 population of GTA34 fraction of plug-in hybrids in Ontario by 202035 number of nights vehicles recharged number of kilometers driven by average car in GTA (km/yr) electrical energy needed for running 1 km (MJ) fraction of electricity supplied to GTA by the energy hub36 conversion factor from MJ to MWh

19,000,000 32,626,363 5,390,412 0.1 250 15,000 0.966 0.133 1/3600

8760 HY R tot

=

∑ [(ViHYTRN × DiGAS × μTRN )

8.2. Hydrogen Reserves. In order to meet the grid electricity demand, the model ensures that the installed fuel cell units always have enough hydrogen to meet power demand when supply is low. If the hydrogen in storage is depleted to quantities lower than the reserve capacity, hydrogen is purchased from the industry at similar prices to that sold by the hub at the given time. The difference between the net hydrogen stored in aboveground and underground facilities is calculated as the excess hydrogen available. Near the end of the year, any excess hydrogen generated is sold equally to local industries and the transportation sector at year-end prices. Nevertheless, in the actual hub operation, a more uniform hydrogen marketing strategy would be developed. 8.3. Aboveground Hydrogen Storage. Hydrogen storage in 20−40 kg aboveground tanks is approximately five times more expensive than underground hydrogen storage, and, therefore, minimizing excess generation of hydrogen is critical. This can be achieved by reducing power generated by nuclear and biomass reactors during periods with large amounts of hydrogen in storage tanks and low power demands. Moreover, if storage tanks are found to have reserves greater than 800,000 kg of hydrogen, biomass reactors are turned off, and the nuclear reactors are run at 60% capacity irrespective of the grid electricity demand. This in turn forces fuel cells to consume some of the hydrogen stored to meet additional power demand.

i=1

+ (ViHYIND × DiNAT × μ IND )]

(20)

where μ and μ are factors for estimating the price of hydrogen used for transportation and industries, respectively. Variables VHYTRN and VHYIND refer to amounts of hydrogen used i i for transportation and industries for hour, i. DNAT and DGAS are i i data for natural gas and gasoline prices in Ontario for hour, i. Since more than 95% of hydrogen is obtained from natural gas, the price of hydrogen is assumed to be closely linked to the price of natural gas. The total annual revenue for the hub, RHUB tot , is calculated by TRN

IND

HUB WIND SUN NUKE BIO FC HY R tot = R tot + R tot + R tot + R tot + R tot + R tot EMISSIONS + R tot

(21)

The profit/loss for the hub is calculated by HUB R tot − CTOT TOT

where C

(22)

is the yearly cost of the energy hub.

8. DEMAND OPTIONS 8.1. Electricity Demand. The total electricity demand is estimated by determining the grid demand from the IESO and G



Article

Table 3. Technology Options for Meeting Grid Electricity Demand with the Lowest Hub Cost solar PV cells capacity (MW) biomass options wind turbine capacity (MW) nuclear capacity (MW) electrolyzer H2 generation capacity (kg/h) hydrogen storage option effective plant cost ($/MWh)

rank 1

rank 2

rank 3

rank 4

rank 5

0 wood, RFD, coal 0 2170 8000 underground 102




5 coal 400 2170 8000 underground 102

Table 4. Analysis of Technologies Considered for the First Scenario total hub cost (M$/yr) total emissions revenue (M$/yr) total hub revenue (M$/yr) profit or loss (M$/yr) effective plant cost ($/MWh)

rank 1

rank 2

rank 3

rank 4

rank 5

1755 432 1403 −351 102

1755 422 1415 −340 102

1762 435 1415 −347 103

1762 425 1,423 −339 103

1725 448 1364 −361 103

Likewise, when hydrogen in storage tanks drops to reserves below 175,000 kg, the nuclear and biomass reactors are ramped up to full capacity to maximize hydrogen production. 8.4. Underground Hydrogen Storage. Since underground hydrogen storage is significantly cheaper than storage tanks, the model assumes there is no limit to the amount of hydrogen stored underground. In the scenario where underground storage is employed, the operations of nuclear reactors are used at peak capacity throughout the year, while those of biomass reactors are maximized depending on feed stock availability.

• Electricity demand and maximizing emissions reduction benefit, which is referred to as ‘Environmental Benefit’ These scenarios were applied to the energy hub location to study the environmental benefits as well as the economical feasibility of developing a clean energy hub in the Ontario area. As outlined in section 7.10, the total revenue for the energy hub includes all environmental revenue and/or cost avoidance obtained by reducing environmental emissions. The calculations for annual emissions revenue are outlined in section 7.9. The effective plant cost is calculated by dividing the annual cost of the hub by the annual energy generated in MWh by the hub.

9. SCENARIOS DEVELOPMENT This study examines 200 different combinations of technologies for the energy hub location. Factorial designs are used for analysis because of the ability to determine the effect of each technology and to analyze the effects of interaction between technologies. In this work a two-level factorial experimental design is implemented to screen technologies to determine the best mix of technologies for each scenario below. During the assessment of the energy hub location, it was observed that there was up to 400 MW of on-shore and offshore wind turbine activity within 100 km of the energy hub location. However, no such similar activity was observed for ground-mounted solar PV systems primarily due to the use of surrounding land for farming activities. Connecting new ground-mounted PV systems to the grid was assumed as not economic. Therefore, only rooftop PV systems are considered for the energy hub. Based on the analysis of the estimated roof area for all the buildings in the energy hub, and the insolation levels in the region, it is estimated that up to 5 MW of roof-top solar PV cells can be incorporated in the energy hub. On the basis of the developmental stage of the hydrogen economy, three scenarios are analyzed in order to meet the main objectives of the following: (1) minimizing hub cost, (2) maximizing hub revenue, and (3) minimizing emissions released. The three scenarios were considered to meet the following: • Electricity demand only, which is referred to as ‘Cost Effective’ • Electricity and hydrogen demand, which is referred to as ‘Hydrogen Economy’

10. SCENARIO ANALYSIS AND DISCUSSION 10.1. Cost Effective Scenario. This scenario represents the period when a hydrogen economy has not yet developed, as a result of which, any excess hydrogen generated would have low market value. However, due to the growing interest in ‘peak shaving’ or ‘load leveling’, storing energy in the form of hydrogen during off-peak hours and using it to produce electricity during peak demand periods was considered. Therefore, the objective of this scenario was to meet the electricity demand of the grid at the lowest price per MWh, while reducing power wastage by converting excess electricity into hydrogen until peak demand hours. Table 3 ranks the top five technology mix options that meet the objectives, on the basis of the lowest hub cost. Table 4 lists the output parameters for the each of the five options. It was found that high electrolyzer capacity, high nuclear reactor capacity, and, consequently, a large amount of fuel cell demand were not favorable options to meet electricity demand at a low hub cost. Since the average grid electricity demand for this hub was 1957 MW, a 2170 MW nuclear reactor running at full capacity at all times was chosen as the most economical option. Fossil based option such as coal to meet the annual peak demands in summer was also part of this scenario. This confirms the need for options other than fuel cells to meet peak electricity demand. Furthermore, it was found that the highest emissions reduction was for the coal only option. This is primarily due to the decreased coal reactor capacity (300 MW) compared to biomass reactor capacity (455 MW), which forced large usage of fuel cells. Additionally, the relatively low yearly costs of coal plants enhance its ability to absorb the higher costs of fuel cell H



Article

Given that there are roughly 3.13 million cars in GTA, if it is assumed that a car would consume 200 kg of hydrogen per year, then the hydrogen produced by the hub annually is enough to serve 10.7% of the automobile industry. Based on work done by the Waterloo Institute of Sustainable Energy,37 this is a potential scenario for years 2025 and beyond. These hubs could be made profitable if CO2 credits are priced at $35, hydrogen costs are a competitive price of $4.82 per kg, and average price of gasoline is assumed as $1.50 per liter for the next 20 years. The electrical demand of the hub in this scenario was met at a cost of 11.09 cents per kWh, while reducing CO2 emissions by 13.5 million tonnes per year. 10.3. Environmental Benefit Scenario. This scenario represents the period when a hydrogen economy is well developed. As a result, any excess hydrogen generated can be sold either to the industrial or transportation sector. However, the objective here was to minimize environmental emissions from all the electricity and hydrogen generated. The model helped in determining the reduction in total emissions, by maximizing revenue from the sale of carbon credits and credits for reduction of other air pollutants. It was assumed that with a reduction in carbon emissions there would also be an associated reduction in other air emissions (e.g., smog generating emissions), which were more difficult to quantify.38 Table 7 outlines the details of the technology mix for maximum emissions reduction. The results of the hub with the greatest emissions reduction are outlined in Table 8.

stacks, use more of the total fuel cell capacity, and, consequently, acquire more emissions revenue by incorporating wind and solar technologies. Although the stated capacity of wind and solar systems is 405 MW, realistically, only 107 MW (26%) of this stated capacity can be utilized due to the intermittent nature of these sources. Therefore, biomass technologies were extensively relied upon to meet the electricity demand, and this resulted in lower costs per MWh for the hub. In summary, for the cost-effective scenario, the future energy hub was found to meet the electricity demand at a cost of 10.23 cents per KWh, while reducing CO2 emissions by approximately 11.6 million tonnes per year. 10.2. Hydrogen Economy Scenario. This scenario represents the period when a hydrogen economy is developed; hence, any excess hydrogen generated can be sold either to the transportation or industrial sector. In this scenario, the objective of the hub was to maximize profit by selling both electricity and hydrogen while meeting grid electricity demand. Since the actual hydrogen demand for industry and transportation are unknown, the model assumed that 50% of all the accumulated hydrogen was sold to industry, and the rest was sold to the transportation sector at year-end prices. The profitability of the hub was expected to increase in this scenario as hydrogen for industry and transportation typically provided more revenue than hydrogen for utilities. Table 5 ranks the top five technology options that met the objective, on the basis of highest profit attained. Table 6 lists the results obtained for each mix.

Table 7. Technologies Chosen To Maximize Emissions Reduction

Table 5. Technology Options for Meeting Grid Electricity Demand and Selling Hydrogen To Maximize Profit rank 1

rank 2

rank 3

rank 4

rank 5

solar PV cells capacity (MW) biomass options

0

5

0

5

5

0 MW 0

wood, RFD 100

0 MW

wind turbine capacity (MW) nuclear capacity (MW) electrolyzer H2 generation capacity (kg/h) hydrogen storage option effective H2 price ($/kg)

wood, RFD 0

100

wood, RFD 300

3200

3200

3200

3200

3200

8000

8000

8000

8000

8000

under ground 4.82

under ground 4.82

under ground 4.82

under under ground ground 4.82 4.82

technology option

capacity

solar PV cells capacity (MW) biomass options (MW) wind turbine capacity (MW) nuclear capacity (MW) electrolyzer H2 generation capacity (kg/h) hydrogen storage option

5 0 400 3200 40,000 underground

Table 8. Output Parameters for Hub with Emissions Reduction

For this scenario, a nuclear reactor capacity of 3200 MW was predominantly chosen to enhance the hub profitability. Biomass did not play an active role in generating electricity, as the case with nuclear reactors and other renewable technologies. The latter two technologies were capable of handling most of the peak demand requirements. The average hydrogen produced at the end of the year was 67 million kg.

output parameter

value

total hub cost (M$/yr) total emissions revenue (M$/yr) total hub revenue (M$/yr) effective plant cost ($/MWh)

2681 536 2425 156

As Table 7 indicates, this was the only case where electrolyzers with hydrogen generation capacities as large as 40,000 kg/h were used. Nevertheless, the electrolyzers were run at only 55% of their capacity. Based on the overall hub cost per MWh, it was concluded that the hub could make a profit if electricity prices escalate up to $70 per MWh, or CO2 prices

Table 6. Analysis of All Potential Technologies for the Second Scenario

total hub cost (M$/yr) total emissions revenue (M$/yr) total hub revenue (M$/yr) profit or loss (M$/yr) effective H2 price ($/kg)

rank 1

rank 2

rank 3

rank 4

rank 5

1902 504 1774 −128 4.82

1904 503 1773 −130 4.82

1926 504 1777 −150 4.82

1927 504 1777 −150 4.82

1967 486 1764 −203 4.82

I



■

escalate up to $ 40 per ton, or gasoline prices increased to a levelized cost of $1.8 per liter over the next 20 years. To conclude, in this scenario, 14.9 million tonnes of CO2 emissions were reduced, 193 million kg of hydrogen was sold to the hydrogen economy at the end of the year at $4.82 per kg, and the power demand of the hub was met at a cost of 15.64 cents per kWh. Although fuel cells were not a desirable option, three nuclear reactors, solar and offshore wind resources were utilized significantly.

Article

AUTHOR INFORMATION

Corresponding Author

*Phone: +971 2 607 5583. Fax: +971 2 607 5200. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

■ ■

MODEL NOTATIONS

PARAMETERS cELECHY amount of hydrogen obtained from electrolyzers (kg/MWh) cFCHY amount of hydrogen required by a fuel cell (kg/ MWh) PONST maximum power for each onshore wind turbine max (MW) μONOF onshore to offshore convertor POFST maximum power for each offshore wind turbine max (MW) μT step-up transformer efficiency (%) μTSD step-down transformer efficiency (%) μSUN solar PV cells efficiency (%) DC/AC inverter efficiency (%) μINV PNUKE maximum nuclear capacity power (MW) max PRDF maximum power capacity of a RDF boiler (MW) max PWOOD maximum power capacity of a woody biomass max boiler (MW) PCOAL maximum power capacity of a coal boiler for the max energy hub (MW) μCOMP compressor efficiency (%) ECOAL emissions in kg per MW of energy from a coal boiler ENAT emissions in kg per kg hydrogen generated from natural gas plants EGAS equivalent gasoline emissions in kg per kg hydrogen used EWOOD emissions in kg per MW of power produced by a woody biomass boiler (kg/MW) ERDF emissions in kg per MW of power produced by a RDF boiler (kg/MW) PCO2 price per kg of CO2 emissions ($/kg) PCO price per kg of CO emissions ($/kg) PNOx price per kg of NOx emissions ($/kg) PSOx price per kg of SOx emissions ($/kg) PVOC price per kg of volatile organic compound emissions ($/kg) PPM price per kg of particulate matter emissions ($/kg) PHM price per kg of heavy metals ($/kg) OMONST operation and maintenance cost per MW for onshore wind turbines ($/MW) CCONST capital costs per MW for each onshore wind turbine ($/MW) OMOFST operation and maintenance cost per MW for offshore wind turbines ($/MW) CCOFST capital costs per MW for each offshore wind turbine ($/MW) PSUN maximum power generated by the solar PEM cells max (MW) OMSUN operation and maintenance cost per MW for solar I panels for hour i ($/MW) CINVSUN inverter costs per MW for solar panels ($/MW) CCMOD capital costs for each solar module ($)

11. CONCLUSION A Matlab/Simulink model for a clean energy hub that consisted of nuclear reactors, solar photovoltaic cells, offshore and onshore wind turbines, biomass reactors, electrolyzers, and fuel cells was developed and analyzed. The hub utilized hydrogen as the energy vector to store energy and thus make use of electrolyzer and fuel cell technology. Generation of hydrogen to be used in the industrial and transportation sectors of the future emerging hydrogen economy was also considered. Detailed energy efficiency and costing analysis was carried out to determine the overall hub cost per MWh of electricity generated. From the 200 technology combinations that were analyzed, three different scenarios for the future energy hub were considered. In the ‘cost-effective’ scenario, the hub was found to meet the electricity demand at a cost of 10.23 cents per KWh, while reducing CO2 emissions by approximately 11.6 million tonnes per year. In the ‘hydrogen economy’ scenario, 67 million kg of hydrogen was sold to the hydrogen economy per year at $4.82 per kg, and the electricity demand of the hub was met at a cost of 11.09 cents per KWh, while reducing CO2 emissions by 13.5 million tonnes per year. In the ‘emission reduction’ scenario, 14.9 million tonnes of CO2 emissions were reduced, 193 million kg of hydrogen was sold to the hydrogen economy per year at $4.82 per kg, while the electricity demand of the hub was met a cost of 15.64 cents per KWh. From the analysis, it was observed that nuclear reactors, followed by biomass reactors, offshore wind turbines, onshore wind turbines, and finally solar panels represent the sequence of technology adoption in order to maximize environmental benefits. In all scenarios, the reduction in CO2 emissions was also associated with a reduction in a number of other air pollutants. The most economical clean energy hub for electricity generation was found to comprise of nuclear reactors with an installed capacity close to the average yearly electricity demand required by the grid. These reactors should be run at full capacity throughout the year, with support from other renewable technologies and fuel cells to meet peak electricity demands. Underground hydrogen storage was the most economical option for all the hubs analyzed. The study concluded that fuel cells were not a cost-effective option for generating electricity even after considering emissions revenues, from cogeneration of hydrogen and electricity. It was more economical to convert excess power into hydrogen using electrolyzers for sale in industrial and transportation sectors. The study also concluded that most of the hub configurations considered in the analysis become economically viable if electricity prices are about 10 cent/kWh, CO2 credits are about $35−40 per tonne, and gasoline prices average approximately $1.50 per liter over the next 20 years. Therefore, these parameters must be closely monitored to determine the profitability of the future energy hub. J


Industrial & Engineering Chemistry Research PNUKE max CCNUKE OMNUKE LUEC

WOOD

LUEC

RDF

LUECCOAL CCELEC OMELEC REPELEC PSTKFC max CCFC OMFC LUECSTG LUECCPR μTRN μ

IND

RHUB tot TOT

C FPH FE EEL

Article

VTRN i

total nuclear capacity (MW) capital and maintenance cost per MW reactor capacity ($/MW) operation and maintenance price per MW power created ($/MW) levelized unit energy cost per MW of power produced by woody biomass boiler ($/MW) levelized unit energy cost per MW of power produced by refuse derived fuel boiler ($/MW) levelized unit energy cost per MW of power produced by coal boiler ($/MW) capital cost for each electrolyzer ($) operation and maintenance costs for each electrolyzer ($) repair costs for each electrolyzer ($) maximum power per stack of fuel cells (MW) capital and fixed costs for fuel cells ($/MW) operation and maintenance costs per MW for fuel cells ($/MW) levelized unit energy cost per kg of hydrogen stored underground ($/kg) levelized unit energy cost for compressor per kg of hydrogen stored ($/kg) factor for estimating the price of hydrogen used for transportation factor for estimating the price of hydrogen used for transportation revenue generated by the hub for the year ($/year) yearly cost of the hub ($/year) fraction of PHEV in Ontario by 2020 fraction of electricity supplied to GTA by the energy hub electrical energy needed in MJ to propel a vehicle for 100 km

PWOOD i PRDF i ETOT RETOT CWIND I CSUN I CNUKE I CBIO I CELEC I CFC I CSTG I CTOT PONST I POFST I PNUKE I PWOOD I PRDF I PCOAL I NFC max PFC I VHY I VHYTRN I VHTIND I RHY tot

Variables

PWIND I PSUN I PNUKE I PBIO I PELEC I PFC I PTOT I VHY I CNOPT I CRWOPT I CCOALOPT I CELECOPT I CFCNUM I PTOT i VIND i

power generated by onshore and offshore wind turbines for hour, i (MW) power generated by solar panels for hour, i (MW) power generated by the nuclear plant for hour, i (MW) power generated by the RDF, woody biomass, and coal boilers for hour, i (MW) power required by the electrolyzers to convert water to hydrogen for hour, i (MW) power generated by the fuel cells using hydrogen for hour, i (MW) total power generated by the energy hub for hour, i (MW) amount of hydrogen in kg in underground storage for hour, i (kg) nuclear reactor run factor for every 6 h of the day (4 a.m./p.m. and 10 a.m./p.m.), represented by j RDF and woody biomass boiler run factor for every 6 h of the day (4 a.m./p.m. and 10 a.m./p.m.), represented by j coal boiler run factor for hour, i electrolyzer run factor for hour, i varying fuel cell number, based on the supply demand power data for the hour, i total power generated by the hub for hour, i (MW) amount of hydrogen in kg used for the industry for hour, i (kg)

amount of hydrogen in kg used for transportation for hour, i (kg) power generated by the woody biomass boiler for hour, i (MW) power generated by the RDF boiler for hour, i (MW) total emissions averted by the energy hub (kg) total revenue obtained from the emissions averted by the energy hub ($) cost of wind energy for hour, i ($) cost of solar energy for hour, i ($) cost of nuclear energy for hour, i ($) cost of biomass energy for hour, i ($) cost of using electrolyzers for hour, i ($) cost of using fuel cells for hour, i ($) cost of hydrogen storage for hour, i ($) total cost of the energy hub for a year ($) power generated by onshore wind turbines for hour, i (MW) power generated by offshore wind turbines for hour, i (MW) power generated by nuclear plant for hour, i (MW) power generated by the woody biomass boiler for hour, i (MW) power generated by RDF boilers for hour, i (MW) power generated by the coal boiler for hour, i (MW) maximum number of fuel cells determined by the model using energy supply−demand data power generated by the fuel cells for hour, i (MW) amount of hydrogen in kg stored underground for hour, i (kg) amount of hydrogen in kg used for transportation for hour, i (kg) amount of hydrogen in kg used for industries for hour i (kg) total revenue obtained from hydrogen for the year ($)

Binary variables

αFCON one if fuel cell is in operation, 0 otherwise I αONOFF one if energy source is in operation, 0 otherwise I Input data

INOST INOFST INRDF INWOOD INCOAL DOST I DTSUN DISUN IASUN IELEC max INPV IMROW NC NKL NRC NH PGTA PC K

number of onshore wind turbines number of offshore wind turbines number of RDF boilers number of woody biomass boilers number of coal boilers hourly onshore wind data for the energy hub location (MW/h) hourly temperature data for the energy hub location (MW/h) hourly insolation data for the energy hub location (MW/h) total area of solar panels (m2) maximum number of electrolyzers number of PV rows number of modules per row number of light vehicles in Canada number of kilometers run by an average car in GTA number of nights vehicles are recharged number of hours electricity is supplied population of GTA population of Canada dx.doi.org/10.1021/ie302161n | Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX


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Article

(23) Cumalioglu, I.; Ertas, A.; Ma, Y.; Maxwell, T. State of the art: hydrogen storage. J. Fuel Cell Sci. Technol. 2008, 5 (3), 034001−031− 10. (24) Riis, T.; Hagen, E. F.; Vie, P. J. S.; Ulleberg, O. Hydrogen storage - gaps and priorities; IEA Hydrogen Implementing Agreement (HIA): 2005; pp 1−12. (25) Lord, A. S. Overview of geologic storage of natural gas with an emphasis on assessing the feasibility of storing hydrogen; Sandia National Laboratories: 2009; pp 1−28. (26) Newborough, M. A report on electrolyzers, future markets and the prospects for ITM Power Ltd’s electrolyzer technology; February, 2004; p 94. (27) Sedighizadeh, M.; Rezazadeh, A. Comparison between batteries and fuel cells for photovoltaic system backup. World Acad. Sci., Eng. Technol. 2007, 36, 295−299. (28) Canadian Hydrogen and Fuel Cell Association About fuel cells. http://www.chfca.ca/itoolkit.asp?pg=ABOUT_FUEL_CELLS (accessed March 20, 2012). (29) Nuclear energy. In Ontario Ministry of Energy and Infrastructure; 2008. (30) Maniyali, Y. Modelling of a Clean Energy Hub with Hydrogen as Energy Vector Using Nanticoke Region as a Case Study; University of Waterloo: Waterloo, 2009. (31) Atomic Energy Canada Ltd (AECL) ACR-1000 Technical Summary; Canada, 2007; p 52. (32) Lomax, S. U.S. prices carbon dioxide at more than $13 a ton in draft plan. In Bloomberg.com, 2009. (33) Transport Canada Transportation in Canada: an overview; Transport Canada: Ottawa, 2008; pp 1−124. (34) Statistics Canada, Population and dwelling counts: 2006 Census. In Statistics Canada; 2008. (35) Nichols, B. A plan for Ontario: 1 in 20 by 2020. In Queen’s Printer for Ontario; 2009. (36) Independent Electricity System Operator (IESO) Hourly Ontario energy price. http://www.ieso.ca (accessed February 8, 2012). (37) Liu, H.; Fowler, M.; Elkamel, A. Analysis of Ontario’s hydrogen economy demands from hydrogen fuel cell vehicles. In International Conference on Hydrogen Production (ICH2P), Oshawa, Ontario, Canada, 2009. (38) Hansen, J.; Sato, M.; Ruedy, R.; Nazarenko, L.; Lacis, A.; Schmidt, A.; Russell, G.; Aleinov, I.; Bauer, M.; Bauer, S.; Bell, N.; Cairns, B.; Canuto, V.; Chandler, M.; Cheng, Y. Efficacy of climate forcings. J. Geophys. Res. 2005, 110, 1−45.

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