A Statistical Analysis of Fluid Interface Fluctuations:Exploring the Role of Viscosity Ratio

Understanding multiphase flow through porous media is integral to geologic carbon storage or hydrogen storage. The current modelling framework assumes each fluid present in the subsurface flows in its own continuously connected pathway. The restriction in flow caused by the presence of another fluid is modelled using relative permeability functions. However, dynamic fluid interfaces have been observed in experimental data, and these are not accounted for in relative permeability functions. In this work, we explore the occurrence of fluid fluctuations in the context of sizes, locations, and frequencies by altering the viscosity ratio for two-phase flow. We see that the fluctuations alter the connectivity of the fluid phases, which, in turn, influences the relative permeability of the fluid phases present

Real‐time imaging reveals distinct pore scale dynamics during transient and equilibrium subsurface multiphase flow

Many subsurface fluid flows, including the storage of CO2 underground or the production of oil, are transient processes incorporating multiple fluid phases. The fluids are not in equilibrium meaning macroscopic properties such as fluid saturation and pressure vary in space and time. However, these flows are traditionally modeled with equilibrium (or steady-state) flow properties, under the assumption that the pore-scale fluid dynamics are equivalent. In this work, we used fast synchrotron X-ray tomography with 1 s time resolution to image the pore-scale fluid dynamics as the macroscopic flow transitioned to steady state. For nitrogen or decane, and brine injected simultaneously into a porous rock, we observed distinct pore-scale fluid dynamics during transient flow. Transient flow was found to be characterized by intermittent fluid occupancy, whereby flow pathways through the pore space were constantly rearranging. The intermittent fluid occupancy was largest and most frequent when a fluid initially invaded the rock. But as the fluids established an equilibrium the dynamics decreased to either static interfaces between the fluids or small-scale intermittent flow pathways, depending on the capillary number and viscosity ratio. If the fluids were perturbed after an equilibrium was established, by changing the flow rate, the transition to a new equilibrium was quicker than the initial transition. Our observations suggest that transient flows require separate modeling parameters. The time scales required to achieve equilibrium suggest that several meters of an invading plume front will have flow properties controlled by transient pore-scale fluid dynamics

Intermittent flow pathways for multiphase flow in porous media: a pore-scale perspective

Subsurface fluid flow is ubiquitous in nature, and understanding the interaction of multiple fluids as they flow within a porous medium is central to many geological, environmental, and industrial processes. It is assumed that the flow pathways of each phase are invariant when modelling subsurface flow using Darcy's law extended to multiphase flow; a condition that is assumed to be valid during steady-state flow. However, it has been observed that intermittent flow pathways exist at steady-state, even at the low capillary numbers typically encountered in the subsurface. In this thesis we use both laboratory-based and synchrotron-based micro-CT imaging to capture the pore-scale flow dynamics that arise when multiple fluids flow simultaneously through the pore space of a rock. Using laboratory-based micro-CT we observed that intermittent flow pathways occur in intermediate sized pores due to the competition between both flowing fluids. This competition moves to smaller pores when the flow rate of the non-wetting phase increases. Intermittency occurs in regions where the non-wetting phase is poorly connected. Intermittency leads to the interrupted transport of the fluids; the impact on flow properties is significant because it occurs at key locations, whereby the non-wetting phase is otherwise disconnected. The amount of intermittency expected during flow is dependent on the capillary number and the viscosity ratio of the fluids. Using fast synchrotron X-ray tomography, with 1~s time resolution, we imaged the pore-scale fluid dynamics as the macroscopic flow transitioned to steady-state, and then during steady-state. We observed distinct behaviour during transient flow, with the intermittent fluid occupancy largest and most frequent during the initial invasion into the rock. Our observations suggest that transient flows require separate modelling parameters. We observed that, during steady-state flow, intermittent fluid transport allows the non-wetting phase to flow through a more ramified network of pores. While a more ramified flow network favours lowered relative permeability, intermittency is more dissipative than laminar flow through connected pathways, and the relative permeability remains unchanged for low capillary numbers, where the pore geometry controls the location of intermittency. As the capillary number increases further, the role of pore structure in controlling intermittency decreases, resulting in an increase in relative permeability. These observations can serve as the basis of a model for the causal links between intermittent fluid flow, fluid distribution throughout the pore space, and its upscaled manifestation in relative permeability.Open Acces

The role of injection method on residual trapping at the pore-scale in continuum-scale samples: segmented data

<p>The experiments in this work explore the role of a variable injection rate on gas saturation and residual trapping. There are 2 experiments in this work H2L (high to low injection rate) and L2H (low to high injection rate). The workflow for processing the micro-CT images to get the segmented images is described in [1]. </p><p>The following scans are included in this repository NB. all data for this repository is segmented micro-CT data.: </p><ol><li>Dry scan prior to experiment = merged_binning_2_38_1927</li><li>H2L during high flow  = merged_segmented_flow_09_h2lh_merged</li><li>H2L during low flow  = merged_segmented_flow_11_h2ll_2_merged</li><li>H2L at the end of drainage (no flow) =merged_segmented_flow_16_dra1_pd5_merged</li><li>H2L at the end of imbibition (no flow) =merged_segmented_flow_21_imb1_pi1_merged</li><li>L2H during low flow = merged_segmented_flow_29_2_l2hl_merged</li><li>L2H during high flow = merged_segmented_flow_30_l2hh_merged</li><li>L2H at the end of drainage (no flow) =merged_segmented_flow_31_dra2_pd1_merged</li><li>L2H at the end of imbibition (no flow)  =merged_segmented_flow_33_imb2_pi1_merged</li></ol&gt

Pore-scale imaging of multiphase flow fluctuations in continuum-scale samples

Representative elementary volumes (REVs) are an important concept in studying subsurface multiphase flow at the continuum scale. However, fluctuations in multiphase flow are currently not represented in continuum scale models, and their impact at the REV-scale is unknown. Previous pore-scale imaging studies on these fluctuations were limited to small samples with mm-scale diameters and volumes on the order of similar to 0.5 cm(3). Here, we image steady-state co-injection experiments on a one-inch diameter core plug sample, with nearly two orders of magnitude larger volume (21 cm(3)), while maintaining a pore-scale resolution with X-ray micro-computed tomography. This was done for three total flow rates in a series of drainage fractional flow steps. Our observations differ markedly from those reported for mm-scale samples in two ways: the macroscopic fluid distribution was less ramified at low capillary numbers (Ca) of 10(-7); and the volume fraction of intermittency initially increased with increasing Ca (similar to mm-scale observations), but then decreased at Ca of 10(-7). Our results suggest that viscous forces may play a role in the cm-scale fluid distribution, even at such low Ca, dampening intermittent pathway flow. A representative elementary volume study of the fluid saturation showed that this may be missed in smaller-scale samples. Pressure drop measurements suggest that the observed pore-scale fluctuations resulted in non-Darcy like upscaled behavior. Overall, we show the usefulness of large field-of-view, high-resolution imaging to bridge the gap between pore- and continuum-scale multiphase flow studies

The role of injection method on residual trapping at the pore-scale in continuum-scale samples

The injection of CO2 into underground reservoirs provides a long term solution for anthropogenic emissions. A variable injection method (such as ramping the flow rate up or down) provides flexibility to injection sites, and could increase trapping at the pore-scale. However, the impact of a variable injection method on the connectivity of the gas, and subsequent trapping has not been explored at the pore-scale. Here, we conduct pore-scale imaging in a continuum-scale sample to observe the role of a variable flow rate on residual trapping. We show that the injection method influences how much of the pore space is accessible to the gas, even when total volumes injected, and total flow rates remain constant. Starting at a low flow rate led to a lower gas saturation at breakthrough. Once a pathway was established across the sample, increasing the flow rate did not improve gas saturation significantly, as the increase in flux was accommodated by the connected pathway across the sample. Starting at a high flow rate led to a higher pore space utilization, which is optimal for CO2 storage. Overall the high to low injection scenario led to more residual trapping

Determination of the spatial distribution of wetting in the pore networks of rocks

Hypothesis: The macroscopic movement of subsurface fluids involved in CO2 storage, groundwater, and petroleum engineering applications is controlled by interfacial forces in the pores of rocks. Recent advances in modelling these systems has arisen from approaches simulating flow through a digital representation of the complex pore structure. However, further progress is limited by difficulties in characterising the spatial distribution of the wetting state within the pore structure. In this work, we show how observations of the fluid coverage of mineral surfaces within the pores of rocks can be used as the basis for a quantitative 3D characterisation of heterogeneous wetting states throughout rock pore structures. Experiments: We demonstrate the approach with water–oil fluid pairs on rocks with distinct lithologies (sandstone and carbonate) and wetting states (hydrophilic, intermediate wetting, and heterogeneously wetting). Findings: Fluid surface coverage the within rock pores is a robust signal of the wetting state across varying rock types and wetting states. The wetting state can be quantified and the resulting 3D maps can be used as a deterministic input to pore scale models. These may be applied to multiphase flow problems in porous media ranging from soil science to fuel cells

Multiphase relaxation processes at the μm-to-cm scale during storage of gases in rocks

The interaction of gases and liquids in the subsurface has become highly relevant as subsurface carbon dioxide sequestration and hydrogen storage have been identified as key technologies to abate climate change. Gas mobility is affected by capillary trapping1, dissolution2 and Ostwald ripening3, as well as the capillary relaxation of the fluid/gas system, with important consequences for gas storage applications. These processes can occur simultaneously within natural porous media and each have their own characteristic time and length scales. The time and length scales over which fluids relax to capillary equilibrium within geological porous media are poorly understood4, particularly in the presence of small-scale capillary heterogeneity5. It is hence unproven whether a sufficient separation of scales exists between capillary relaxation and trapping, gas dissolution and Ostwald ripening to model these processes independently. In this work, we investigated the coupled relaxation processes at the pore scale in a 25 x 45 mm Bentheimer sandstone sample, using the HECTOR micro-CT scanner at UGCT6 to image the pore space at 10 µm resolution. Using a sample that was one order of magnitude larger than typically used in pore-scale investigations made it possible to study the effect of length scales where viscous forces and capillary heterogeneity come into play. We conducted core floods with post-drainage and post-imbibition relaxation, using nitrogen (as model carbon dioxide/hydrogen) and KI brine at a pore pressure of 50 bar. After each fluid invasion, the sample was isolated and maintained at a constant pressure. Preliminary results reveal significant differences between the relaxation processes after drainage and imbibition. Following drainage, the system appears to reach equilibrium almost instantly, with no visible changes in the fluid distribution being observed over the course of several hours. This is in stark contrast with the observations made during imbibition, where the system continues to change even 18 hours after imbibition is stopped. Understanding relaxation, and all the processes associated with it, has implications for storage security and efficiency during carbon dioxide sequestration and subsurface energy storage. 1. Krevor, S. et al. Capillary trapping for geologic carbon dioxide storage - From pore scale physics to field scale implications. Int. J. Greenh. Gas Control 40, 221–237 (2015). 2. Huang, R., Herring, A. L. & Sheppard, A. Investigation of supercritical CO2 mass transfer in porous media using X-ray micro-computed tomography. Adv. Water Resour. 116950 (2022) doi:10.1016/j.advwatres.2022.104338. 3. Blunt, M. J. Ostwald ripening and gravitational equilibrium: Implications for long-term subsurface gas storage. Phys. Rev. E 106, 1–6 (2022). 4. Schlüter, S., Berg, S., Li, T., Vogel, H.-J. & Wildenschild, D. Time scales of relaxation dynamics during transient conditions in two-phase flow. Water Resour. Res. 53, 4709–4724 (2017). 5. Jackson, S. J. & Krevor, S. Small-Scale Capillary Heterogeneity Linked to Rapid Plume Migration During CO2 Storage. Geophys. Res. Lett. 47, (2020). 6. Masschaele, B. et al. HECTOR: A 240kV micro-CT setup optimized for research. J. Phys. Conf. Ser. 463, (2013)

Red Noise in Steady-State Multiphase Flow in Porous Media

Understanding the interaction between competing fluids in the pore space of rocks is key for predicting subsurface flow and trapping, such as with CO2 in a saline aquifer. These processes occur over a large span of timescales (from seconds to thousands of years), and length scales (from microns to kilometers). Understanding the link between these temporal and spatial scales will enable us to interpolate between observations made at different resolutions. In this work we explore the temporal scales present during macroscopically steady-state multiphase flow in a porous carbonate rock using differential pressure measurements acquired over a period of 60 min. Nitrogen and brine were injected simultaneously into a sample 5 mm in diameter and 21 mm in length. We observe a cascade of timescales in the pressure differential that is, a continuous range of frequencies, with lower frequencies having greater amplitudes. We demonstrate a scaling of the spectral density with frequency of S ∼ 1/f2, or red noise, to describe the dynamics. This scaling is independent of the flow rate of the fluids or the fraction of the flow taken by water. This red, or Brownian, noise indicates a stochastic process where pressure fluctuations are seen throughout the pore space, resulting in intermittent filling of pores over a wide range of time-scales, from seconds to minutes in these experiments. The presence of red noise suggests self-organized critically, with no characteristic time or length scale.</p