Use this URL to cite or link to this record in EThOS: http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.638887
Title: Geological storage of carbon dioxide in the UK : opportunities and risks
Author: Lynch, Thomas Oakley
ISNI:       0000 0004 5362 7333
Awarding Body: University of Leeds
Current Institution: University of Leeds
Date of Award: 2014
Availability of Full Text:
Access from EThOS:
Access from Institution:
Abstract:
Climate change caused by greenhouse gas emissions from anthropogenic sources, primarily from fossil fuel combustion, is a major global challenge that threatens many serious adverse impacts, including sea level rise, food and water scarcity, extreme weather events and species extinction. Curbing global emissions from fossil fuels has become a major and urgent priority. Carbon Capture and Storage (CCS) has been proposed as a method to capture greenhouse gas (GHG) emissions from large point source fossil fuel combustion and store these emissions away from the atmosphere to reduce the impact on the climate. CCS involves capturing the predominant GHG produced in fossil fuel combustion, CO2, at the point source and transporting it to a location where is can be stored for thousands of years to limit its impact on the climate. Geological storage is considered to be the most advanced and realistic option for CO2 storage, and is the focus of this thesis. The aim of this thesis is to assess the risks and opportunities for CO2 storage in the UK offshore region, where the majority of UK CO2 storage capacity is expected to exist in saline aquifers and depleted hydrocarbon reservoirs. A review of the technical considerations for geological CO2 storage is presented and the potential storage capacities and risks to secure storage in the UK are identified. Fluid flow simulation and coupled fluid flow-geomechanical modelling are used to assess several aspects of storage, based on the assessment of the potential risks for storage in the UK. These include assessment of current capacity estimates for CO2 injection into the largest potential source of UK storage capacity the Bunter Saline Aquifer; opportunities for brine extraction to increase capacity in saline aquifers and the potential for a reduction in capacity and risk of leakage through fracture pressure hysteresis in depleted hydrocarbon reservoirs. Three key results are identified from the work. Firstly, significantly lower capacities are modelled for the Bunter Aquifer, compared to both static estimates and more complex models in the literature. This is due to the potential variability in parameters, such as the compressibility and fracture pressure, which control capacity. Estimates for the capacity in the Bunter from the modelling range between 3.1 and 8.7 Gt CO2 which corresponds to between 20 and 56 years of storage capacity for the UK, this is compared to an initial estimate of 90 years of storage capacity from static estimates. Fracture pressure estimation is uncertain and fracture pressure is a significant control on capacity in the generic modelling it is shown to reduce capacity by 32 – 60% with a 20% reduction in fracture pressure. The most conservative fracture pressure assumption for the modelled capacities in the Bunter Aquifer would indicate a reduced capacity as low as 2.5 Gt CO2 . Potential variability in the fracture pressure is the second major finding of this work and is intrinsically related to variability in capacity. Coupled fluid flow geomechanical modelling indicates that the fracture pressure in depleted hydrocarbon reservoirs with similar stress conditions and material parameters to those found in the UK North Sea could be up to 19% lower during injection compared to the depletion fracture pressures. This is without including the effect of thermally induced tensile stresses developed due to the injection of cold CO2 which may reduce fracture pressures further. Finally, capacity modelling in the Bunter Aquifer has also identified a potential legacy risk for CO2 storage in a large aquifer such as the Bunter. The peak fracture pressure risk is not observed in the model until 6 – 136 years after injection has stopped, and occurs great distances from the injection point. This poses questions as to the methodology for monitoring this risk, the potential remediation options and the impact on other activities within the aquifer. The research highlights several areas where further investigation are essential for constraining CO2 storage capacity and leakage risks, with the primary uncertainty relating to the quantification of fracture pressure in both saline aquifers and depleted hydrocarbon reservoirs.
Supervisor: Fisher, Q. J. ; Angus, D. A. ; Williams, P. T. Sponsor: Not available
Qualification Name: Thesis (Ph.D.) Qualification Level: Doctoral
EThOS ID: uk.bl.ethos.638887  DOI: Not available
Share: