Pore-scale mechanisms of CO2 storage in oilfields

Abstract

Rapid implementation of global scale carbon capture and storage is required to limit temperature rises to 1.5 °C this century. Depleted oilfields provide an immediate option for storage, since injection infrastructure is in place and there is an economic benefit from enhanced oil recovery. To design secure storage, we need to understand how the fluids are configured in the microscopic pore spaces of the reservoir rock. We use high-resolution X-ray imaging to study the flow of oil, water and CO 2 in an oil-wet rock at subsurface conditions of high temperature and pressure. We show that contrary to conventional understanding, CO 2 does not reside in the largest pores, which would facilitate its escape, but instead occupies smaller pores or is present in layers in the corners of the pore space. The CO 2 flow is restricted by a factor of ten, compared to if it occupied the larger pores. This shows that CO 2 injection in oilfields provides secure storage with limited recycling of gas; the injection of large amounts of water to capillary trap the co 2 is unnecessary. With anthropogenic CO 2 emissions into the atmosphere of 37 GtCO 2 in 2018 1 , fuelled by the growth in fossil fuel consumption 2 , any viable solution to avoid dangerous climate change has to involve the rapid and large-scale implementation of CO 2 capture and storage (CCS) 3-9. Although there are abundant CO 2 storage sites in deep saline aquifers 10 , given the short time frame to implement the technology at a global scale, geological storage of CO 2 in the next decade is most practical in depleted oil and gas reservoirs, where the infrastructure including facilities, pipelines, and injection wells, as well as detailed knowledge of the fields already exists, combined with an immediate financial incentive from enhanced oil recovery (EOR) 11-14 , see Fig. 1. In CO 2-EOR projects, the injection of CO 2 into depleted oil and gas reservoirs can result in an additional hydrocarbon recovery, which may offset some of the cost of CO 2 capture and storage 15-17. While depleted oil and gas reservoirs are well known for their commercial quality permitting investment into large-scale EOR-CCS projects, they typically contain abandoned boreholes, which can potentially be conduits for rapid escape of stored CO 2. How should CO 2 injection be designed to maximize storage security? While CO 2 underground migrates over several kilometres, the physical processes that control its movement occur at the micron-scale of the pores within the rock 18. In saline aquifers, subsequent to the injection of CO 2 , water imbibes back into the pore space either at the trailing edge of a rising CO 2 plume or through engineered water injection. Since water wets the rock surfaces in saline aquifers, water flows through wetting layers, leaving CO 2 , the non-wetting phase, stranded in the centres of the larger pores in disconnected blobs, see Fig. 1B; hence a significant amount of CO 2 can become trapped in the subsurface 19,20. This capillary, or residual, trapping is important, as otherwi...

Dynamics of water injection in an oil-wet reservoir rock at subsurface conditions: Invasion patterns and pore-filling events

“…The low oil recovery factor seen is attributed to water invading the centers of the pores, leaving oil connected in thick wetting layers in the corners and crevices of the pore space. This behavior was observed in previous water flooding static experiments conducted on the same rock type [74].…”

Three-phase flow displacement dynamics and Haines jumps in a hydrophobic porous medium

“…This is attributed to (i) water being the most non-wetting phase, and hence it remains preferentially in the larger pores ( figure 6) and (ii) the preferential displacement of oil by gas in the smaller-sized pores. The gas saturation reaches only 24 ± 5%, which is similar to saturation values observed on the same reservoir rock previously during unsteady-state flooding [15].…”

“…Furthermore, the existence of a phase in the centre of the pores permits its trapping in the form of disconnected bubbles by the more wetting phases. It has been shown that wettability order is a function of surface wettability and liquid–gas miscibility, either immiscible or near-miscible conditions [ 12 , 14 , 15 ].…”

“…Furthermore, Alhosani et al . [ 15 ] observed the formation of gas spreading layers in an oil-wet carbonate rock under near-miscible conditions. The spreading of a fluid phase can have a direct impact on contact angles and fluid configurations with a major influence on flow properties [ 12 ].…”

In Situ Characterization of Three‐Phase Flow in Mixed‐Wet Porous Media Using Synchrotron Imaging

“…At near‐miscible conditions, when the properties of the gas and oil are similar, it is possible to observe layers of gas (Alhosani et al, 2020). However, in our experiments, where oil and gas are immiscible, using Equation and Table 2, C sg = −22.7 mN/m, which is large and negative, indicating that gas layers will not form.…”