472 results found
Alhosani A, Lin Q, Scanziani A, et al., 2021, Pore-scale characterization of carbon dioxide storage at immiscible and near-miscible conditions in altered-wettability reservoir rocks, International Journal of Greenhouse Gas Control, Vol: 105, ISSN: 1750-5836
© 2020 The Authors Carbon dioxide storage combined with enhanced oil recovery (CCS-EOR) is an important approach for reducing greenhouse gas emissions. We use pore-scale imaging to help understand CO2 storage and oil recovery during CCS-EOR at immiscible and near-miscible CO2 injection conditions. We study in situ immiscible CO2 flooding in an oil-wet reservoir rock at elevated temperature and pressure using X-ray micro-tomography. We observe the predicted, but hitherto unreported, three-phase wettability order in strongly oil-wet rocks, where water occupies the largest pores, oil the smallest, while CO2 occupies pores of intermediate size. We investigate the pore occupancy, existence of CO2 layers, recovery and CO2 trapping in the oil-wet rock at immiscible conditions and compare to the results obtained on the same rock type under slightly more weakly oil-wet near-miscible conditions, with the same wettability order. CO2 spreads in connected layers at near-miscible conditions, while it exists as disconnected ganglia in medium-sized pores at immiscible conditions. Hence, capillary trapping of CO2 by oil occurs at immiscible but not at near-miscible conditions. Moreover, capillary trapping of CO2 by water is not possible in both cases since CO2 is more wetting to the rock than water. The oil recovery by CO2 injection alone is reduced at immiscible conditions compared to near-miscible conditions, where low gas-oil capillary pressure improves microscopic displacement efficiency. Based on these results, to maximize the amount of oil recovered and CO2 stored at immiscible conditions, a water-alternating-gas injection strategy is suggested, while a strategy of continuous CO2 injection is recommended at near-miscible conditions.
Blunt MJ, Alhosani A, Lin Q, et al., 2021, Determination of contact angles for three-phase flow in porous media using an energy balance, Journal of Colloid and Interface Science, Vol: 582, Pages: 283-290, ISSN: 0021-9797
HYPOTHESIS: We define contact angles, θ, during displacement of three fluid phases in a porous medium using energy balance, extending previous work on two-phase flow. We test if this theory can be applied to quantify the three contact angles and wettability order in pore-scale images of three-phase displacement. THEORY: For three phases labelled 1, 2 and 3, and solid, s, using conservation of energy ignoring viscous dissipation (Δa1scosθ12-Δa12-ϕκ12ΔS1)σ12=(Δa3scosθ23+Δa23-ϕκ23ΔS3)σ23+Δa13σ13, where ϕ is the porosity, σ is the interfacial tension, a is the specific interfacial area, S is the saturation, and κ is the fluid-fluid interfacial curvature. Δ represents the change during a displacement. The third contact angle, θ13 can be found using the Bartell-Osterhof relationship. The energy balance is also extended to an arbitrary number of phases. FINDINGS: X-ray imaging of porous media and the fluids within them, at pore-scale resolution, allows the difference terms in the energy balance equation to be measured. This enables wettability, the contact angles, to be determined for complex displacements, to characterize the behaviour, and for input into pore-scale models. Two synchrotron imaging datasets are used to illustrate the approach, comparing the flow of oil, water and gas in a water-wet and an altered-wettability limestone rock sample. We show that in the water-wet case, as expected, water (phase 1) is the most wetting phase, oil (phase 2) is intermediate wet, while gas (phase 3) is most non-wetting with effective contact angles of θ12≈48° and θ13≈44°, while θ23=0 since oil is always present in spreading layers. In contrast, for the altered-wettability case, oil is most wetting, gas is intermediate-wet, while water is most non-wetting with contact angles of θ12=134°±~10°,θ13=119°&p
Lin Q, Akai T, Blunt MJ, et al., 2021, Pore-scale imaging of asphaltene-induced pore clogging in carbonate rocks, Fuel, Vol: 283, ISSN: 0016-2361
We propose an experimental methodology to visualize asphaltene precipitation in the pore space of rocks and assess the reduction in permeability. We perform core flooding experiments integrated with X-ray microtomography (micro-CT). The simultaneous injection of pure heptane and crude oil containing asphaltene induces the precipitation of asphaltene in the pore space. The degree of precipitation is controlled by the measurement of differential pressure across the sample. After precipitation, doped heptane is injected to replace the fluid to enhance the contrast between precipitated asphaltene and doped heptane. The micro-CT images are segmented into three phases: void, precipitated asphaltene, and rock. In the experiment, we observed that the precipitated asphaltene which occupied 39.1% of the pore volume caused a 29-fold reduction in permeability. Furthermore, we analyze the spatial distribution of precipitated asphaltene which showed that the asphaltene tended to clog the larger pores. We also computed the flow field numerically on the images and obtained good agreement between simulated and measured permeability. The distribution of local velocity showed that after precipitation the flow was confined to narrow channels in the pore space. This method can be applied to any type of porous system with precipitation.
Alhosani A, Scanziani A, Lin Q, et al., 2020, Three-phase flow displacement dynamics and Haines jumps in a hydrophobic porous medium, PROCEEDINGS OF THE ROYAL SOCIETY A-MATHEMATICAL PHYSICAL AND ENGINEERING SCIENCES, Vol: 476, ISSN: 1364-5021
Rezaeizadeh M, Hajiabadi SH, Aghaei H, et al., 2020, Pore-scale analysis of formation damage; A review of existing digital and analytical approaches., Adv Colloid Interface Sci, Vol: 288
Formation damage is one of the most challenging problems that occurs during the lifetime of a well. Despite numerous previous studies, an organized review of the literature that introduces and describes the digital and analytical approaches developed for formation damage analysis is lacking. This study aims to fill this gap through briefly describing the main mechanisms behind formation damage in porous media as well as investigating the main related experimental methods with an emphasis on novel imaging techniques. Specifically, there will be a focus on a number of modern and nondestructive analytical methods, such as dry/cryogenic Scanning Electron Microscopy (SEM), X-Ray Diffraction (XRD), CT-scanning (both using adapted medical scanners and the use of high-resolution micro-CT instruments) and Nuclear Magnetic Resonance (NMR), which obtain outstanding results for the identification of formation damage mechanisms. These approaches when used in combination provide a robust identification of damage processes, while they reduce the risk of operational mistakes for decision makers through visualization of the distribution, severity, and nature of the damage mechanisms.
Spurin C, Bultreys T, Rucker M, et al., 2020, Real-Time Imaging Reveals Distinct Pore-Scale Dynamics During Transient and Equilibrium Subsurface Multiphase Flow, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
Alhosani A, Scanziani A, Lin Q, et al., 2020, Three-phase flow displacement dynamics and Haines jumps in a hydrophobic porous medium: Three-Phase Flow in Porous Media, Proceedings of the Royal Society A: Mathematical, Physical and Engineering Sciences, Vol: 476, ISSN: 1364-5021
© 2020 The Authors. We use synchrotron X-ray micro-tomography to investigate the displacement dynamics during three-phase-oil, water and gas-flow in a hydrophobic porous medium. We observe a distinct gas invasion pattern, where gas progresses through the pore space in the form of disconnected clusters mediated by double and multiple displacement events. Gas advances in a process we name three-phase Haines jumps, during which gas re-arranges its configuration in the pore space, retracting from some regions to enable the rapid filling of multiple pores. The gas retraction leads to a permanent disconnection of gas ganglia, which do not reconnect as gas injection proceeds. We observe, in situ, the direct displacement of oil and water by gas as well as gas-oil-water double displacement. The use of local in situ measurements and an energy balance approach to determine fluid-fluid contact angles alongside the quantification of capillary pressures and pore occupancy indicate that the wettability order is oil-gas-water from most to least wetting. Furthermore, quantifying the evolution of Minkowski functionals implied well-connected oil and water, while the gas connectivity decreased as gas was broken up into discrete clusters during injection. This work can be used to design CO 2 storage, improved oil recovery and microfluidic devices.
Gao Y, Raeini AQ, Selem AM, et al., 2020, Pore-scale imaging with measurement of relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions, Advances in Water Resources, Vol: 146, Pages: 1-18, ISSN: 0309-1708
Using micro-CT imaging and differential pressure measurements, we design a comparative study in which we simultaneously measure relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions during steady-state waterflooding experiments. This allows us to isolate the impact of wettability on a pore-by-pore basis and its effect on the macroscopic parameters, capillary pressure and relative permeability, while keeping the pore-space geometry unchanged.First, oil and brine were injected through a water-wet reservoir sandstone sample at a fixed total flow rate, but in a sequence of increasing brine fractional flows with micro-CT scans of the fluid phases taken in each step. Then the sample was brought back to initial water saturation and the surface wettability of the sample was altered after prolonged contact with crude oil and the same measurement procedure was repeated on the altered-wettability sample which we call mixed-wet.Geometric contact angles were measured, which discriminated the water-wet and mixed-wet cases with average values of 75° and 89° respectively. Additionally, an energy balance was used to determine the effective contact angles for displacement which indicated that a higher advancing contact angle of 116° was needed to displace oil in the mixed-wet case. For the water-wet experiment the filling sequence was pore-size dependent, with a strong correlation between pore size and oil occupancy. However, in the mixed-wet experiment the principal determinant of the filling sequence was the wettability rather than the pore size, and there was no correlation between pore size and the residual oil occupancy.The oil-water interfacial area had a larger maximum in the mixed-wet case which was supported by the observation of sheet or saddle-like menisci shapes present throughout the sample volume that impede the flow. These shapes were quantified by much larger negative Gaussian curvature
Zhang Z, Wang T, Blunt MJ, et al., 2020, Advances in carbon capture, utilization and storage, APPLIED ENERGY, Vol: 278, ISSN: 0306-2619
Akai T, Lin Q, Bijeljic B, et al., 2020, Using energy balance to determine pore-scale wettability, Journal of Colloid and Interface Science, Vol: 576, Pages: 486-495, ISSN: 0021-9797
HypothesisBased on energy balance during two-phase displacement in porous media, it has recently been shown that a thermodynamically consistent contact angle can be determined from micro-tomography images. However, the impact of viscous dissipation on the energy balance has not been fully understood. Furthermore, it is of great importance to determine the spatial distribution of wettability. We use direct numerical simulation to validate the determination of the thermodynamic contact angle both in an entire domain and on a pore-by-pore basis.SimulationsTwo-phase direct numerical simulations are performed on complex 3D porous media with three wettability states: uniformly water-wet, uniformly oil-wet, and non-uniform mixed-wet. Using the simulated fluid configurations, the thermodynamic contact angle is computed, then compared with the input contact angles.FindingsThe impact of viscous dissipation on the energy balance is quantified; it is insignificant for water flooding in water-wet and mixed-wet media, resulting in an accurate estimation of a representative contact angle for the entire domain even if viscous effects are ignored. An increasing trend in the computed thermodynamic contact angle during water injection is shown to be a manifestation of the displacement sequence. Furthermore, the spatial distribution of wettability can be represented by the thermodynamic contact angle computed on a pore-by-pore basis.
Blunt MJ, Akai T, Bijeljic B, 2020, Evaluation of methods using topology and integral geometry to assess wettability, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 576, Pages: 99-108, ISSN: 0021-9797
Scanziani A, Alhosani A, Lin Q, et al., 2020, In situ characterization of three‐phase flow in mixed‐wet porous media using synchrotron imaging, Water Resources Research, Vol: 56, ISSN: 0043-1397
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.
Alhosani A, Scanziani A, Lin Q, et al., 2020, Dynamics of water injection in an oil-wet reservoir rock at subsurface conditions: Invasion patterns and pore-filling events, Physical Review E, Vol: 102, Pages: 023110 – 1-023110 – 15, ISSN: 2470-0045
We use fast synchrotron x-ray microtomography to investigate the pore-scale dynamics of water injection in an oil-wet carbonate reservoir rock at subsurface conditions. We measure, in situ, the geometric contact angles to confirm the oil-wet nature of the rock and define the displacement contact angles using an energy-balance-based approach. We observe that the displacement of oil by water is a drainagelike process, where water advances as a connected front displacing oil in the center of the pores, confining the oil to wetting layers. The displacement is an invasion percolation process, where throats, the restrictions between pores, fill in order of size, with the largest available throats filled first. In our heterogeneous carbonate rock, the displacement is predominantly size controlled; wettability has a smaller effect, due to the wide range of pore and throat sizes, as well as largely oil-wet surfaces. Wettability only has an impact early in the displacement, where the less oil-wet pores fill by water first. We observe drainage associated pore-filling dynamics including Haines jumps and snap-off events. Haines jumps occur on single- and/or multiple-pore levels accompanied by the rearrangement of water in the pore space to allow the rapid filling. Snap-off events are observed both locally and distally and the capillary pressure of the trapped water ganglia is shown to reach a new capillary equilibrium state. We measure the curvature of the oil-water interface. We find that the total curvature, the sum of the curvatures in orthogonal directions, is negative, giving a negative capillary pressure, consistent with oil-wet conditions, where displacement occurs as the water pressure exceeds that of the oil. However, the product of the principal curvatures, the Gaussian curvature, is generally negative, meaning that water bulges into oil in one direction, while oil bulges into water in the other. A negative Gaussian curvature provides a topological quantification of th
Foroughi S, Bijeljic B, Lin Q, et al., 2020, Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks, Physical Review E: Statistical, Nonlinear, and Soft Matter Physics, Vol: 102, Pages: 023302 – 1-023302 – 15, ISSN: 1539-3755
A pore-network model is an upscaled representation of the pore space and fluid displacement, which is used to simulate two-phase flow through porous media. We use the results of pore-scale imaging experiments to calibrate and validate our simulations, and specifically to find the pore-scale distribution of wettability. We employ energy balance to estimate an average, thermodynamic, contact angle in the model, which is used as the initial estimate of contact angle. We then adjust the contact angle of each pore to match the observed fluid configurations in the experiment as a nonlinear inverse problem. The proposed algorithm is implemented on two sets of steady state micro-computed-tomography experiments for water-wet and mixed-wet Bentheimer sandstone. As a result of the optimization, the pore-by-pore error between the model and experiment is decreased to less than that observed between repeat experiments on the same rock sample. After calibration and matching, the model predictions for capillary pressure and relative permeability are in good agreement with the experiments. The proposed algorithm leads to a distribution of contact angle around the thermodynamic contact angle. We show that the contact angle is spatially correlated over around 4 pore lengths, while larger pores tend to be more oil-wet. Using randomly assigned distributions of contact angle in the model results in poor predictions of relative permeability and capillary pressure, particularly for the mixed-wet case.
Scanziani A, Lin Q, Alhosani A, et al., 2020, Dynamics of fluid displacement in mixed-wet porous media, Proceedings of the Royal Society A: Mathematical, Physical and Engineering Sciences, Vol: 476, Pages: 1-16, ISSN: 1364-5021
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.
Bultreys T, Singh K, Raeini AQ, et al., 2020, Verifying pore network models of imbibition in rocks using time‐resolved synchrotron imaging, Water Resources Research, Vol: 56, Pages: 1-13, ISSN: 0043-1397
At the pore scale, slow invasion of a wetting fluid in porous materials is often modeled with quasi‐static approximations which only consider capillary forces in the form of simple pore‐filling rules. The appropriateness of this approximation, often applied in pore network models, is contested in the literature, reflecting the difficulty of predicting imbibition relative permeability with these models. However, validation by sole comparison to continuum‐scale experiments is prone to induce model overfitting. It has therefore remained unclear whether difficulties generalizing the model performance are caused by errors in the predicted filling sequence or by subsequent calculations. Here, we address this by examining whether such a model can predict the pore‐scale fluid distributions underlying the behavior at the continuum scale. To this end, we compare the fluid arrangement evolution measured in fast synchrotron micro‐CT experiments on two rock types to quasi‐static simulations which implement capillary‐dominated pore filling and snap‐off, including a sophisticated model for cooperative pore filling. The results indicate that such pore network models can, in principle, predict fluid distributions accurately enough to estimate upscaled flow properties of strongly wetted rocks at low capillary numbers.
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 CO2 in an oil-wet rock at subsurface conditions of high temperature and pressure. We show that contrary to conventional understanding, CO2 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 CO2 flow is restricted by a factor of ten, compared to if it occupied the larger pores. This shows that CO2 injection in oilfields provides secure storage with limited recycling of gas; the injection of large amounts of water to capillary trap the CO2 is unnecessary.
Mularczyk A, Lin Q, Blunt MJ, et al., 2020, Droplet and percolation network interactions in a fuel cell gas diffusion layer, Journal of The Electrochemical Society, Vol: 167, ISSN: 0013-4651
Product water accumulations in polymer electrolyte fuel cells can cause performance losses and reactant starvation leading to cell degradation. Liquid water removal in the form of droplets, fed by percolation networks in the gas diffusion layer (GDL), is one of the main transport mechanisms by which the water is evacuated from the GDL. In this study, the effect of droplet detachment in the gas channel on the water cluster inside the GDL has been investigated using X-ray tomographic microscopy and X-ray radiography. The droplet growth is captured in varying stages over a sequence of consecutive droplet releases, during which an inflation and deflation of the gas-liquid interface menisci of the percolating water structure in the GDL has been observed and correlated to changes in pressure fluctuations in the water phase via gas-liquid curvature analysis.
Alhammadi AM, Gao Y, Akai T, et al., 2020, Pore-scale X-ray imaging with measurement of relative permeability, capillary pressure and oil recovery in a mixed-wet micro-porous carbonate reservoir rock, Fuel, Vol: 268, Pages: 1-14, ISSN: 0016-2361
Differential imaging X-ray microtomography combined with a steady-state flow apparatus was used to elucidate the displacement processes during waterflooding. We simultaneously measured relative permeability and capillary pressure on a carbonate rock sample extracted from a giant producing oil field. We used the pore-scale images of crude oil and brine to measure the interfacial curvature from which the local capillary pressure was calculated; the relative permeability was found from the imposed fractional flow, the image-measured saturation, and the pressure differential across the sample.The relative permeabilities indicated favourable oil recovery for the mixed-wettability conditions. The pore-scale images showed that brine started to flow through pinned wetting layers, micro-porosity and water-wet pores, and then filled the centre of the larger oil-wet pores. Oil was drained to low saturation through connected oil layers. The brine relative permeability remained low until brine invaded a connected pathway of smaller throats at a high brine saturation. The interface between the oil and brine had a small average curvature, indicating a low capillary pressure, but we observed remarkable saddle-shaped interfaces with nearly equal but opposite curvatures in orthogonal directions. This implies good oil phase connectivity, consistent with the favourable recovery and low residual oil saturation attained in the experiments.This work illuminated displacement processes from both macro-pores and micro-pores which have important implications for improved oil recovery and, potentially, on carbon storage. In future, the measured relative permeability, capillary pressure and pore-scale fluid distribution could be used to benchmark and validate pore-scale models.
Akai T, Blunt MJ, Bijeljic B, 2020, Pore-scale numerical simulation of low salinity water flooding using the lattice Boltzmann method, Journal of Colloid and Interface Science, Vol: 566, Pages: 444-453, ISSN: 0021-9797
HYPOTHESIS: The change of wettability toward more water-wet by the injection of low salinity water can improve oil recovery from porous rocks, which is known as low salinity water flooding. To simulate this process at the pore-scale, we propose that the alteration in surface wettability mediated by thin water films which are below the resolution of simulation grid blocks has to be considered, as observed in experiments. This is modeled by a wettability alteration model based on rate-limited adsorption of ions onto the rock surface. SIMULATIONS: The wettability alteration model is developed and incorporated into a lattice Boltzmann simulator which solves both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport. The model is validated against two experiments in the literature, then applied to 3D micro-CT images of a rock. FINDINGS: Our model correctly simulated the experimental observations caused by the slow wettability alteration driven by the development of water films. In the simulations on the 3D rock pore structure, a distinct difference in the mixing of high and low salinity water is observed between secondary and tertiary low salinity flooding, resulting in different oil recoveries.
Rücker M, Bartels W-B, Bultreys T, et al., 2020, Workflow for upscaling wettability from the nano- to core-scales, International Symposium of the Society of Core Analysts
Shams R, Masihi M, Boozarjomehry RB, et al., 2020, Coupled generative adversarial and auto-encoder neural networks to reconstruct three-dimensional multi-scale porous media, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 186, ISSN: 0920-4105
Akai T, Bijeljic B, Blunt M, 2020, Local Capillary Pressure Estimation Based on Curvature of the Fluid Interface-Validation with Two-Phase Direct Numerical Simulations, ISSN: 2555-0403
© The Authors, published by EDP Sciences, 2020. With the advancement of high-resolution three-dimensional X-ray imaging, it is now possible to directly calculate the curvature of the interface of two phases extracted from segmented CT images during two-phase flow experiments to derive capillary pressure. However, there is an inherent difficulty of this image-based curvature measurement: The use of voxelized image data for the calculation of curvature can cause significant errors. To address this, we first perform two-phase direct numerical simulations to obtain the oil and water phase distribution, the exact location of the interface, and local fluid pressure. We then investigate a method to compute curvature on the oil/water interface. The interface is defined in two ways. In one case the simulated interface which has a sub-resolution smoothness is used, while the other is a smoothed interface which is extracted from synthetic segmented data based on the simulated phase distribution. Computed mean curvature on these surfaces are compared with that obtained from the fluid pressure computed directly in the simulation. We discuss the accuracy of image-based curvature measurements for the calculation of capillary pressure and propose the best way to extract an accurate curvature measurement, quantifying the likely uncertainties.
Scanziani A, Singh K, Menke H, et al., 2020, Dynamics of enhanced gas trapping applied to CO2 storage in the presence of oil using synchrotron X-ray micro tomography, Applied Energy, Vol: 259, ISSN: 0306-2619
During CO2 storage in depleted oil fields, under immiscible conditions, CO2 can be trapped in the pore space by capillary forces, providing safe storage over geological times - a phenomenon named capillary trapping. Synchrotron X-ray imaging was used to obtain dynamic three-dimensional images of the flow of the three phases involved in this process - brine, oil and gas (nitrogen) - at high pressure and temperature, inside the pore space of Ketton limestone. First, using continuous imaging of the porous medium during gas injection, performed after waterflooding, we observed chains of multiple displacements between the three phases, caused by the connectivity of the pore space. Then, brine was re-injected and double capillary trapping - gas trapping by oil and oil trapping by brine - was the dominant double displacement event. We computed pore occupancy, saturations, interfacial area, mean curvature and Euler characteristic to elucidate these double capillary trapping phenomena, which lead to a high residual gas saturation. Pore occupancy and saturation results show an enhancement of gas trapping in the presence of both oil and brine, which potentially makes CO2 storage in depleted oil reservoirs attractive, combining safe storage with enhanced oil recovery through immiscible gas injection. Mean curvature measurements were used to assess the capillary pressures between fluid pairs during double displacements and these confirmed the stability of the spreading oil layers observed, which facilitated double capillary trapping. Interfacial area and Euler characteristic increased, indicating lower oil and gas connectivity, due to the capillary trapping events.
Synchrotron x-ray microtomography combined with sensitive pressure differential measurements were used to study flow during steady-state injection of equal volume fractions of two immiscible fluids of similar viscosity through a 57-mm-long porous sandstone sample for a wide range of flow rates. We found three flow regimes. (1) At low capillary numbers, Ca, representing the balance of viscous to capillary forces, the pressure gradient, ∇P, across the sample was stable and proportional to the flow rate (total Darcy flux) qt (and hence capillary number), confirming the traditional conceptual picture of fixed multiphase flow pathways in porous media. (2) Beyond Ca∗≈10−6, pressure fluctuations were observed, while retaining a linear dependence between flow rate and pressure gradient for the same fractional flow. (3) Above a critical value Ca>Cai≈10−5 we observed a power-law dependence with ∇P∼qat with a≈0.6 associated with rapid fluctuations of the pressure differential of a magnitude equal to the capillary pressure. At the pore scale a transient or intermittent occupancy of portions of the pore space was captured, where locally flow paths were opened to increase the conductivity of the phases. We quantify the amount of this intermittent flow and identify the onset of rapid pore-space rearrangements as the point when the Darcy law becomes nonlinear. We suggest an empirical form of the multiphase Darcy law applicable for all flow rates, consistent with the experimental results.
Ladipo L, Blunt MJ, King PR, 2020, A salinity cut-off method to control numerical dispersion in low-salinity waterflooding simulation, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 184, ISSN: 0920-4105
Mosser L, Dubrule O, Blunt MJ, 2020, Stochastic Seismic Waveform Inversion Using Generative Adversarial Networks as a Geological Prior, MATHEMATICAL GEOSCIENCES, Vol: 52, Pages: 53-79, ISSN: 1874-8961
© 2020, Avestia Publishing. All rights reserved. The Hubbert curve was first introduced seventy years ago, to estimate oil reserves and production in the US. In this paper, Hubbert’s logistic function is used to estimate the peak production of natural gas of the top producers worldwide. The aim is to manage and fit the historic data with the minimum error and eventually project the CO2 emissions that result if the estimated reserves are extracted. Finally, we try to answer how the carbon budget is affected if production continues unconstrained. To that extend, historic data of the major producers were fitted and both production and expected emissions, were estimated. For several countries, the logistic function presented an adequate fit, while for others, it did not. The countries that didn’t fall under the bell-shaped (Hubbert) curve, have made political decisions to constrain their production. Continuing with the other countries (so called reference countries) we estimate that their cumulative emissions from natural gas production, will account for 59% of worldwide emissions by 2050, with China and the US dominating. Most importantly, in the case of no action for mitigating the emissions, total CO2 emitted, from natural gas production only, will consume 85% of the available carbon budget by 2050 to limit expected temperature increases to1.5 C and 31% of the budget in the case of a 2 C temperature increase.
Krevor S, Blunt MJ, Trusler JPM, et al., 2020, Chapter 8: An introduction to subsurface CO<inf>2</inf> storage, RSC Energy and Environment Series, Pages: 238-295, ISBN: 9781788014700
© The Royal Society of Chemistry 2020. The costs of carbon capture and storage are driven by the capture of CO2 from exhaust streams or the atmosphere. However, its role in climate change mitigation is underpinned by the potential of the vast capacity for storage in subsurface geologic formations. This storage potential is confined to sedimentary rocks, which have substantial porosity and high permeability in comparison to crystalline igneous and metamorphic rocks. These in turn occur in the sedimentary basins of the Earth's continents and near shore. However, the specific capacity for storage is not correlated simply to the existence of a basin. Consideration must also be made of reservoir permeability, caprock integrity, injectivity, fluid dynamics, and geomechanical properties of pressurisation and faulting. These are the topics addressed in this chapter. These processes and properties will combine in complex ways in a wide range of settings to govern the practicality of storing large volumes of CO2. There is clear potential for storage at the scale required to mitigate the worst impacts of global climate change, estimated to be in the order of 10 Gt CO2 per year by 2050. However, until at least dozens of commercial projects have been built in a range of geologic environments, the upper reaches of what can be achieved, and how quickly, will remain uncertain.
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