Dynamics of enhanced gas trapping applied to CO2 storage in the presence of oil using synchrotron X-ray micro tomography

Scanziani, Alessio; Singh, Kamaljit; Menke, Hannah P.; Bijeljic, Branko; Blunt, Martin J.

doi:10.1016/j.apenergy.2019.114136

Cited by 57 publications

(52 citation statements)

References 58 publications

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“…We compare and discuss our results in the light of previous measurements made on a similar water-wet system (Scanziani et al, 2018;Scanziani, Singh, et al, 2020) and the same rock under near-miscible conditions (Alhosani et al, 2019) using the Minkowski functionals to quantify our observations (section 3.5). Finally, we will place our work in context by exploring the implications for storage, recovery, and the performance optimization of manufactured porous devices.…”

Section: Introductionmentioning

confidence: 61%

“…Again, unlike the water-wet case, the principal displacement process during WF2 is direct displacement of oil by water; there is little contact between water and gas, as the gas is surrounded by wetting and spreading layers of oil-described in the next section. We observed some double displacement events-water-gas-oil-as seen in water-wet rocks as well (Scanziani et al, 2018;Scanziani, Singh, et al, 2020), where water displaces oil that traps gas. This causes oil layers to swell and trap gas by snap-off.…”

Section: Second Waterfloodingmentioning

confidence: 70%

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

Scanziani

Alhosani

Lin

et al. 2020

Water Resources Research

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We use fast synchrotron X-ray microtomography to understand three-phase flow in mixed-wet porous media to design either enhanced permeability or capillary trapping. The dynamics of these phenomena are of key importance in subsurface hydrology, carbon dioxide storage, oil recovery, food and drug manufacturing, and chemical reactors. We study the dynamics of a water-gas-water injection sequence in a mixed-wet carbonate rock. During the initial waterflooding, water displaced oil from pores of all size, indicating a mixed-wet system with local contact angles both above and below 90 •. When gas was injected, gas displaced oil preferentially with negligible displacement of water. This behavior is explained in terms of the gas pressure needed for invasion. Overall, gas behaved as the most nonwetting phase with oil as the most wetting phase; however, pores of all size were occupied by oil, water, and gas, as a signature of mixed-wet media. Thick oil wetting layers were observed, which increased oil connectivity and facilitated its flow during gas injection. A chase waterflooding resulted in additional oil flow, while gas was trapped by oil and water. Furthermore, we quantified the evolution of the surface areas and both Gaussian and the total curvature, from which capillary pressure could be estimated. These quantities are related to the Minkowski functionals which quantify the degree of connectivity and trapping. The combination of water and gas injection, under mixed-wet immiscible conditions, leads to both favorable oil flow and significant trapping of gas, which is advantageous for storage applications.

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Section: Introductionmentioning

confidence: 61%

Section: Second Waterfloodingmentioning

confidence: 70%

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

Scanziani

Alhosani

Lin

et al. 2020

Water Resources Research

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“…PV are computed considering the total macro pores of the whole sample which could be resolved with the image resolution of 3.5 µm (porosity and dimensions of the sample are available in table 1). Firstly, we note that waterflooding in this mixed-wet rock happened differently to imbibition in water-wet systems: pore centres were invaded first, and oil was not isolated by snap-off [11,35].…”

Section: (A) Experimental Observation Of Invasion Patternsmentioning

confidence: 89%

Dynamics of fluid displacement in mixed-wet porous media

et al. 2020

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We identify a distinct two-phase flow invasion pattern in a mixed-wet porous medium. Time-resolved high-resolution synchrotron X-ray imaging is used to study the invasion of water through a small rock sample filled with oil, characterized by a wide non-uniform distribution of local contact angles both above and below 90 ° . The water advances in a connected front, but throats are not invaded in decreasing order of size, as predicted by invasion percolation theory for uniformly hydrophobic systems. Instead, we observe pinning of the three-phase contact between the fluids and the solid, manifested as contact angle hysteresis, which prevents snap-off and interface retraction. In the absence of viscous dissipation, we use an energy balance to find an effective, thermodynamic, contact angle for displacement and show that this angle increases during the displacement. Displacement occurs when the local contact angles overcome the advancing contact angles at a pinned interface: it is wettability which controls the filling sequence. The product of the principal interfacial curvatures, the Gaussian curvature, is negative, implying well-connected phases which is consistent with pinning at the contact line while providing a topological explanation for the high displacement efficiencies in mixed-wet media.

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“…We performed a topological analysis of the pore space to identify the widest regions (pores) that are connected by narrower restrictions: the pore size is the diameter of the largest sphere that fits in a pore; the centre of the sphere is the centre of the pore. The phase occupancy is defined as the phase which resides at the centre of the pore 29,36,39 . We find that water is the most non-wetting phase since it occupies the largest pores, followed by gas, with oil most wetting in the smallest pores.…”

Section: Distribution Of Co 2 Oil and Water In The Pore Spacementioning

confidence: 99%

Pore-scale mechanisms of CO2 storage in oilfields

Alhosani

Scanziani

Lin

et al. 2020

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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...

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Dynamics of enhanced gas trapping applied to CO2 storage in the presence of oil using synchrotron X-ray micro tomography

Cited by 57 publications

References 58 publications

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

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

Dynamics of fluid displacement in mixed-wet porous media

Pore-scale mechanisms of CO2 storage in oilfields

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