|dc.description.abstract||Challenges faced by an electricity sector transitioning towards a lower carbon footprint can be seen as an opportunity for energy technologies that are able to address them. Surplus energy generation is one of the biggest issues faced by the provincial power grid of Ontario. In 2017, the IESO exported approximately 7.3 TWh of surplus electricity. This adds up to almost 5.54% of the province’s annual energy demand and equivalent to meeting the electricity demand of 9.8 million homes. Power to gas energy hubs represent a novel concept that could help in effectively repurposing surplus electricity generation. This concept proposes to utilize the surplus electricity to produce hydrogen via the water electrolysis process. Hydrogen as an energy vector enables the storage and distribution of surplus electricity through an entirely different energy system (e.g. natural gas grid).
The implementation of this idea is of particular interest in the context of Ontario as this work proposes to utilize the existing natural gas distribution infrastructure to distribute the electrolytic hydrogen. Linking of the electrical distribution and natural gas distribution system will allow Ontario to form a seamless integrated energy system.
This work looks at repurposing surplus electricity via hydrogen in the natural gas and transportation sector within Ontario. More specifically, this thesis focusses on estimating the cost of reducing emissions by servicing natural gas end users with a hydrogen enriched natural gas (HENG) blend and renewable natural gas (RNG) (produced by combining electrolytic hydrogen with biogenic CO2 from organic waste processing facilities). These costs have estimate to be $87 and $228 per tonne of lifecycle CO2,e emissions offset at the natural gas end user for using HENG and RNG, respectively. The cost of reducing emissions in the natural gas sector is then compared with what the province’s electric and hydrogen vehicle incentive program offers in the transportation sector. For the 9056 (4760 battery and 4296 plug-in hybrid) electric vehicles that qualified for incentives at the end of 2016, it will cost the province of Ontario $732 per tonne of CO2,e to offset emissions over an 8 year lifetime (with each vehicles mileage being 180,000 km). This comparison shows the potential incentive structures required for power to gas energy hubs, and electric vehicles, both of which represent ways to repurpose surplus electricity within the province. Electric vehicles and power to gas both are important technologies that reduce emissions by utilizing clean low emission surplus electricity, this comparison tries to highlight how power to gas can also be a part of a holistic solution.
In addition to this, the thesis highlights the potential scale of electrolyzer systems required to absorb all of Ontario’s surplus electricity and gives a brief overview of potential end uses of hydrogen in Ontario’s 10 different power zones. It is seen that an electrolyzer system capacity close 3179 MW would be required to absorb all of the surplus electricity generated in 2016 (5.3 TWh) within the province. Following this, a business case analysis from a 2 MW power to gas demonstration project within the greater Toronto area has been presented. This analysis focuses on valuing: 1) The price of hydrogen as a fuel for fuel cell vehicles; 2) The incentive received by on-site electrolyzer to provide demand response ancillary service to the power grid, and 3) The CO2,e emission offset allowance that the power to gas requires when it offsets emissions at natural gas end users. The evaluation shows that to achieve a short payback of 8 years (desirable for the energy hub investors) hydrogen sold to the transportation sector should be valued at a price higher ($6.71 per kg) than its levelized cost of production ($3.66 per kg). The current demand response ancillary service incentive structure ($ 0.0215 per kWh) does not account for technologies such as power to gas providing demand response. Therefore for such technologies to be able to provide this service, the business cost for power to gas energy hubs to curb load while providing multiple services such as hydrogen refueling is evaluated and should be close to $0.039 per kWh. The price of carbon emission allowances in the cap and trade program (~$18 per tonne of CO2,e) are not valued high enough and the values should increase to at least $28 per tonne of CO2,e emissions offset. The valuation of all these services within Ontario has been compared and seen to be well within what global trends have shown.
The last piece of analysis shown in this thesis includes assessing the impact of uncertainty in electricity price and fuel cell vehicle hydrogen demand on the sizing and operation of a power to gas energy hub. The impact of uncertainty on how the energy hub responds to deterministic data sets such as a demand response ancillary service requirement has also been evaluated. A 17 MW system has been sized with on-site tank storage capacity of 1869 kg to provide hydrogen demand for a hypothetical market penetration scenario of 1766 fuel cell vehicles within the GTA. This penetration scenario is scaled down from trends developed for the US by the Oak Ridge National Laboratory. Positive values for the ‘Expected Value of Perfect Information’ ($57,211) and the ‘Value of Stochastic Solution’ ($104,276) highlight the value of obtaining perfect information on the uncertain parameters and the cost savings achievable when uncertainty has been accounted for.
Through the analysis presented in this thesis some of the potential barriers for the implementation of such technologies has been highlighted in chapter 8. Some of the primary challenges include the energy storage technologies being subject to market uplift charges such as global adjustment which significantly increases their cost to be competitive. If energy storage technologies are included in the electricity system operators dispatch scheduling optimization engine as dispatchable loads some of these uplift charges would reduce as a result of electricity market clearing price increasing and reaching values close to what contracted generation facilities need to be paid. Energy storage technologies have not been included in the provinces industrial conservation initiatives. There are no clear roles, regulations (including safety standards) defined by the Ontario Energy Board or in other legislations within the province. The valuation of the additional services (e.g., emission reduction, surplus baseload generation management, enabling higher penetration of renewables) has not been studied by regulators within the province. In order to drive investment in energy storage projects, the regulators of the electricity sector need to provide better access to reliable, and current data. This will help investors to understand the regions where there are potential opportunities for such projects within the province.
The four different analyses outlined above show that power to gas energy hubs can be cost competitive when compared with other technologies (such as battery and plug in hybrid electric vehicles) that repurpose surplus off-peak power or excess intermittent renewable power within a different energy sector. Power to gas energy hubs located within urban communities can provide multiple energy recovery pathways while being within agreement of current and projected market prices (H2 enriched natural gas, H2 as a transportation fuel, demand response ancillary service, CO2,e emission offset allowance). Accounting for uncertainty in parametric input data proves to be more valuable than its deterministic counterpart. Overall, this thesis tries to highlight the potential for power to gas energy hubs and what roles it could play in Ontario’s long term energy future.||en