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dc.contributor.advisorWilkinson, Mark
dc.contributor.advisorGilfillan, Stuart
dc.contributor.advisorHeinemann, Niklas
dc.contributor.advisorHaszeldine, Stuart
dc.contributor.authorScafidi, Jonathan
dc.date.accessioned2022-06-29T16:38:31Z
dc.date.available2022-06-29T16:38:31Z
dc.date.issued2022-06-29
dc.identifier.urihttps://hdl.handle.net/1842/39250
dc.identifier.urihttp://dx.doi.org/10.7488/era/2501
dc.description.abstractThe Paris Agreement to limit anthropogenic warming to 1.5 °C above pre-industrial levels requires rapid reduction of greenhouse gas emissions. The UK has a large natural gas demand which varies massively across the year, with peaks in winter up to five times as high as the lows in summer. Decarbonising this system will require an emissions-free alternative to natural gas coupled with large-scale seasonal storage. Hydrogen can be used as an alternative to natural gas as it releases no CO2 when burned. Hydrogen can also be used to store renewable electricity during times of surplus, as well as buffering hydrogen production from natural gas coupled with CCS. The aim of this thesis is to investigate the potential for seasonal storage of hydrogen in depleted gas fields with a focus on the UK. There are three main parts to this thesis: a regional capacity estimate for the UK continental shelf; a reservoir engineering, geological modelling, and hydrogen storage simulation study of an onshore gas field; and the development of an open-source tool for the accurate estimation of the flow rates and cushion gas requirements of gas storage sites. A high-level assessment of gas fields on the UK continental shelf for hydrogen storage potential was undertaken, alongside calculations of the seasonal storage requirement for the 100% replacement of natural gas demand in the UK with hydrogen. UK natural gas demand over the past five years has exceeded was 800 TWh with peak daily demand in winter reaching almost 5 TWh/day compared to summer lows of 1 to 1.5 TWh/day. Using monthly demand data an estimate of 150 TWh of seasonal hydrogen storage is required to replace seasonal variations in natural gas production. A method is determined to screen gas fields and saline aquifers for suitability, however it is found that the estimates for saline aquifers are extremely low confidence due to a lack of data. Gas fields are able to hold 13,800 TWh of hydrogen and assuming a cushion gas requirement of 50%, this gives a value of 6900 TWh working gas capacity for hydrogen across 95 gas fields. Of these 85% are in the Southern North Sea which could utilise existing infrastructure and large offshore wind developments to develop large-scale offshore hydrogen production. As depleted gas fields still contain some natural gas, there is a need to investigate the effects of storing hydrogen in such a field. The Cousland gas field, a small, 0.9 billion cubic feet (BCF) gas field in Scotland was selected for a simulation study. The field had previously been earmarked for town gas storage in the 1960s and so a reservoir engineering study was performed using well testing and production data from the 1930s to 1960s. From this study, a geological model was developed and history matched against the results of the reservoir engineering study and production data. Three one-well, 20 year hydrogen storage scenarios at different pressures were then simulated. Hydrogen was injected for 2 years, allowed to settle for 2 years, then 14 storage cycles of injection, storage, extraction, and empty were completed before a final depletion of the cushion gas over 1 year. The initial volume injected into the reservoir had little effect on the hydrogen recovery factor, storage capacity, well flow rates, produced gas composition, and pressure response. The extracted hydrogen showed less contamination with natural gas over time and the results show that the mixed zone between the hydrogen and natural gas was pushed further from the well with each subsequent storage cycle. The field has a capacity of close to 1000 tonnes of hydrogen with recovery factors higher than 90%. The natural gas in the reservoir behaved as a cushion gas, and hydrogen purity could be controlled through injection strategies. Cushion gas requirements for gas storage sites are important for both deliverability and economics, and, outside of reservoir simulation studies, cushion gas requirements are generally assumed. The final chapter of this thesis describes an open-source program designed to improve these assumptions. The programs uses basic reservoir parameters (original reservoir pressure, average permeability, average porosity, formation thickness, depth, gas initially in place, and reservoir temperature ) for volumetric gas fields to calculate the working and cushion gas volumes, expected flow rates, and well performance. The program uses an open-source fluid property database (CoolProp) to model the properties of both methane and hydrogen. LIT (laminar-inertial-turbulent) and pseudopressure equations are used to solve the generalized radial-flow diffusivity equation which allows the program to be used on reservoirs of all pressures. Bottom hole flowing pressure is computed using the average temperature and compressibility method. As the program is open-source the code can be downloaded and adjusted according to need. The program is validated using data from four real gas storage sites. The results from these four sites are used to compare hydrogen and methane gas storage performance and finds that similar levels of performance can be achieved in terms of energy deliverability with hydrogen showing significantly lower cushion gas requirements than methane, particularly for the higher pressure, larger fields. The results suggest that cushion gas requirements and deliverability are not entirely dependent on reservoir properties but can be changed significantly by adjusting the number of wells and well diameter. A simple economics model shows that this has implications for the optimal number of wells drilled in a storage site.en
dc.contributor.sponsorNatural Environment Research Council (NERC)en
dc.language.isoenen
dc.publisherThe University of Edinburghen
dc.relation.hasversionHeinemann, N., Booth, M.G., Haszeldine, R.S., Wilkinson, M., Scafidi, J. and Edlmann, K. 2018a. Hydrogen storage in porous geological formations – onshore play opportunities in the midland valley (Scotland, UK). International Journal of Hydrogen Energy, 43, 20861–20874, https://doi.org/10.1016/j.ijhydene.2018.09.149.en
dc.relation.hasversionHeinemann, N., Booth, M.G., Haszeldine, R.S., Wilkinson, M., Scafidi, J. and Edlmann, K. 2018b. Hydrogen storage in porous geological formations – onshore play opportunities in the midland valley (Scotland, UK). International Journal of Hydrogen Energy, 43, 20861–20874, https://doi.org/10.1016/J.IJHYDENE.2018.09.149.en
dc.relation.hasversionHeinemann, N., Scafidi, J., et al. 2021b. Hydrogen storage in saline aquifers: The role of cushion gas for injection and production. International Journal of Hydrogen Energy, 46, 39284–39296, https://doi.org/10.1016/j.ijhydene.2021.09.174.en
dc.relation.hasversionScafidi, J., Wilkinson, M., Gilfillan, S.M.V., Heinemann, N. and Haszeldine, R.S. 2021. A quantitative assessment of the hydrogen storage capacity of the UK continental shelf. International Journal of Hydrogen Energy, 46, 8629–8639, https://doi.org/10.1016/j.ijhydene.2020.12.106.en
dc.subjectgreenhouse gasesen
dc.subjectglobal warmingen
dc.subjectParis Agreementen
dc.subjecthydrogen storageen
dc.subjectgas field storesen
dc.subjectstoring hydrogen in porous rocksen
dc.subjecthigh pressure storageen
dc.subjectcushion gasen
dc.subjecthydrogen storage sitesen
dc.titleHydrogen storage in depleted gas fields: capacity and performanceen
dc.typeThesis or Dissertationen
dc.type.qualificationlevelDoctoralen
dc.type.qualificationnamePhD Doctor of Philosophyen


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