The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

CO2 sequestration in saline aquifers and hydrocarbon reservoirs is a promising strategy to reduce CO2 concentration in the atmosphere and/or enhance hydrocarbon production. Change in subsurface conditions of pressure and temperature and CO2 state is likely to have a significant impact on capillary and viscous forces, which, in turn, will have a considerable influence on the injection, migration, displacement, and storage capacity and integrity of CO2 processes. In this study, an experimental investigation has been performed to explore the impact of fluid pressure, temperature, and injection rate, as a function of CO2 phase, on the dynamic pressure evolution and the oil recovery performance of CO2 during oil displacement in a Berea sandstone core sample. The results reveal a considerable impact of the fluid pressure, temperature, and injection rate on the differential pressure profile, cumulative produced volumes, endpoint CO2 relative permeability, and oil recovery; the trend and the size of the changes depend on the CO2 phase as well as the pressure range for gaseous CO2–oil displacement. The residual oil saturation was in the range of around 0.44–0.7; liquid CO2 gave the lowest, and low-fluid-pressure gaseous CO2 gave the highest. The endpoint CO2 relative permeability was in the range of about 0.015–0.657; supercritical CO2 gave the highest, and low-pressure gaseous CO2 gave the lowest. As for increasing fluid pressure, the results indicate that viscous forces were dominant in subcritical CO2 displacements, while capillary forces were dominant in supercritical CO2 displacements. As temperature and CO2 injection rates increase, the viscous forces become more dominant than capillary forces

Understanding the interplay of capillary and viscous forces in CO2 core flooding experiments

Interaction between capillary and viscous forces significantly affects the flow instability in immiscible displacement, which is usually investigated by visualization of flow patterns in 2d porous micromodels or in 3d system equipped with X-ray CT. However, in most practical applications, visualization of flow in porous media is not possible and the pressure signal is often as one of the important sources of information. Core flooding experiments were implemented in this study to investigate the interplay of capillary and viscous effects by analysis of differential pressure. Water and crude oil were employed as defending fluid, and different states of CO2 were injected as invading fluid. The inlet was set as the constant injection flow rate while the outlet as the constant pressure. In viscous-dominated displacement, differential pressure evidently depends on the injection rate and the pressure decline curve is fitted by a power function. The exponent of the function is found to be significantly larger at the crossover between capillary-dominated and viscous-dominated regions. In capillary-dominated displacement, the pressure profile is characterized by a pressure jump at the beginning and intermittent fluctuations during the displacement. Further analysis by wavelet decomposition indicates a transition point existing in standard deviation of pressure fluctuations when the displacement is transformed from capillary-dominated to viscous-dominated. The experimental results are finally verified by a macroscopic capillary number, which characterizes the interaction between capillary and viscous forces at a critical value of , agreeing well with the Log Nca-Log M phase diagram

Enabling secure subsurface storage in future energy systems: An introduction

Geological structures in the subsurface have been used for the storage of energy and waste products for over a century. Depleted oil and gas fields, saline aquifers or engineered caverns in salt or crystalline rocks are used worldwide to store energy fluids intended to provide demand buffers and sustained energy supply. The transition of our energy system into a clean, renewable-based system will most likely require an expansion of these subsurface storage activities, to host a wide variety of energy products (e.g. natural gas, hydrogen, heat or waste energy products, like CO2) to balance the inherent intermittence of the renewable energy supply. Ensuring the safety and effectiveness of these subsurface storage operations is therefore crucial to achieve the sought-after renewable energy transition while ensuring energy security

Mapping hydrogen storage capacities of UK offshore hydrocarbon fields and exploring potential synergies with offshore wind

Energy storage is an essential component of the transitioning UK energy system, a crucial mechanism for stabilising intermittent renewable electricity supply and meeting seasonal variation in demand. Low-carbon hydrogen provides a balancing mechanism for variable renewable energy supply and demand, and a method for decarbonising domestic heating, essential for meeting the UK's 2050 net-zero targets. Geological hydrogen storage in porous rocks offers large-scale energy storage over a variety of timescales and has promising prospects due to the widespread availability of UK offshore hydrocarbon fields, with established reservoirs and existing infrastructure. This contribution explores the potential for storage within fields in the UK Continental Shelf. Through comparison of available energy storage capacity and current domestic gas demands, we quantify the hydrogen required to decarbonise the UK gas network. We estimate a total hydrogen storage capacity of 3454TWh, significantly exceeding the 120TWh seasonal domestic demand. Multi-criteria decision analysis, in consultation with an expert focus group, identified optimal fields for coupling with offshore wind, which could facilitate large-scale renewable hydrogen production and storage. These results will be used as inputs for future energy system modelling, optimising potential synergies between offshore oil and gas and renewables sectors, in the context of the energy transition.ISSN:0375-6440ISSN:0305-8719ISSN:2041-492