In the context of the development of renewable energy sources in the U.K., and of the increase in anthropogenic atmospheric CO2, it is important to develop alternative ways of providing energy to the community. The shift to renewable sources of electricity comes to a cost: variable generation. At present, an important part of the renewable electricity capacity is being curtailed during low demand periods. One way to ensure that electricity supply matches demand is to store excess energy when it is available and deliver it when demand cannot be met by primary generation alone. Compressed Air Energy Storage (CAES) allows this storage. The aim of this project is to build upon existing knowledge on CAES using porous rocks (PM-CAES) to assess the technical feasibility for this storage technology to be developed offshore of the UK. The focus is on inter-seasonal storage. This assessment is undertaken by developing geological and power plant models to calculate the storage potential of offshore UK formations. Modelling of a conceptual aquifer air store enables approximations of the subsurface pressure response to CAES operations. These pressure changes are coupled with surface facilities models to provide estimates of both load/generation capacity and roundtrip efficiencies. Algebraic predictive models can be developed from the results of a sensitivity analysis of the store and plant idealised models. Screening of the CO2 Stored database, containing data on geological formations offshore of the UK (initially developed for CO2 storage), was then performed to estimate PM-CAES potential using the predictive models. The results suggest that there is substantial PM-CAES potential in the UK. Results indicate an energy storage potential in the range of 77-96 TWh, which can be released over 60 days. A geographic information system (GIS) study was then performed to identify the portion of the identified storage potential colocated with offshore windfarm. 19 TWh of the storage potential identified is colocated with windfarm and would be achievable at an average levelised cost of electricity of 0.70 £/kWh.

This thesis presents an experimental investigation of two-phase flow properties of porous rock samples having different scales ranging from micro-CT imaging to conventional core plug scales. Advances in micro-CT imaging of porous materials provide the opportunity to extract representative networks from the images. This improves the predictive capability of porescale network models to predict multiphase flow properties. However, all these predictions need to be validated with laboratory data. Micro-CT imaging is currently limited to small sample sizes, having bulk volumes of the order of 0.1 cm??. Conventional core plugs, however, have sizes several orders of magnitude larger than that (bulk volumes of 10 cm?? or larger). The aim of this thesis is to investigate the scale effect on laboratory data and to provide reliable experimental data which can be used to test the predictive value of microCT based network models. Berea and Bentheim sandstones and Mount Gambier carbonate were used in the experiments. The core samples were thoroughly cleaned in order to obtain strongly, uniform water-wet conditions. Simple well-characterized fluid systems were chosen in the experiments: Air-brine fluid-system for drainage capillary pressure, resistivity index and spontaneous imbibition experiments while oil-brine fluid-system for wettability and relative permeability measurements. Drainage capillary pressure, resistivity index, relative permeability and spontaneous imbibition measurements were made on the cores having bulk volumes ranging from 0.1 to 12 cm??. Previous studies have shown that experiments at this scale are still lacking. The wettability was tried to keep strongly water-wet for all experiments. The experimental results show that the measurements of drainage capillary pressure, and resistivity index and spontaneous imbibition on small core samples, having similar scales as micro-CT imaging can be made accurately in the laboratory. The measurement of relative permeability remains challenging. This thesis concludes that commonly used homogeneous rock types (Berea and Bentheim sandstones and Mt. Gambier carbonate) can be considered to be sufficiently homogeneous from the pore to core scale based on the two-phase flow properties examined in this study. Hence, laboratory data taken from these rocks using conventional core plugs can be used to calibrate micro-CT based network models for multiphase flow properties.

Partial saturation of porous rock by two fluids substantially affects compressional wave propagation. In particular, partial saturation causes significant attenuation and dispersion due to wave-induced fluid flow. Such flow arises when a passing wave induces different fluid pressures in regions of rock saturated by different fluids. When partial saturation is mesoscopic, i.e. existing on a length scale much greater than pore scale but less than wavelength scale, significant attenuation can arise for frequencies 10-1000 Hz. Models for attenuation and dispersion due to mesoscale heterogeneities mostly assume fluids are distributed in a regular way. Recent experiments indicate mesoscopic heterogeneities have less idealised distributions and distribution affects attenuation/dispersion. Thus, theoretical models are required to simulate effects due to realistic fluid distributions. / The thesis focus is to model attenuation and dispersion due to realistic mesoscopic fluid distributions and fluid contrasts. First X-ray tomographic images of partially saturated rock are analysed statistically to identify spatial measures useful for describing fluid distribution patterns. The correlation function and associated correlation length for a specific fluid type are shown to be of greatest utility. Next a new model, called 3DCRM (CRM stands for continuous random media) is derived, utilizing a correlation function to describe the fluid distribution pattern. It is a random media model, is accurate for small fluid contrast and approximate for large fluid contrast. Using 3DCRM attenuation and dispersion are shown to depend on fluid distribution. / Next a general framework for partial saturation called APS (acoustics of partial saturation) is extended enabling estimation of attenuation and dispersion due to arbitrary 1D/3D fluid distributions. The intent is to construct a versatile model enabling attenuation and dispersion to be estimated for arbitrary fluid distributions, contrasts and saturations. Two crucial parameters within APS called shape and frequency scaling parameters are modified via asymptotic analysis using several random media models (which are accurate for only certain contrasts in fluid bulk moduli and percent saturation). For valid fluid contrasts and saturations, which satisfy certain random media conditions there is good correspondence between modified APS and the random media models, hence showing that APS can be utilized to model attenuation and dispersion due to more realistic fluid distributions. / Finally I devise a numerical method to test the accuracy of the analytical shape parameters for a range of fluid distributions, saturations and contrasts. In particular, the analytical shape parameter for randomly distributed spheres was shown to be accurate for a large range of saturations and fluid contrasts.