Imperial College London

Dr. Samuel Krevor

Faculty of EngineeringDepartment of Earth Science & Engineering

Senior Lecturer
 
 
 
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Contact

 

+44 (0)20 7594 2701s.krevor

 
 
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Location

 

1.43Royal School of MinesSouth Kensington Campus

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Summary

 

Publications

Publication Type
Year
to

109 results found

Jackson SJ, Krevor S, 2020, Small-Scale Capillary Heterogeneity Linked to Rapid Plume Migration During CO<inf>2</inf> Storage, Geophysical Research Letters, Vol: 47, ISSN: 0094-8276

©2020. The Authors. Unpredicted, rapid plume elongation has been observed at subsurface CO2 storage projects worldwide, exemplified by the Sleipner project. We show that conventionally ignored centimeter-meter scale heterogeneity in capillary pressure characteristics can manifest as rapid field-scale, decameter-kilometer, plume migration. We analyze the effect in the Goldeneye field, UK, a proposed storage site with a unique combination of sample/data accessibility and generality as an archetype sandstone reservoir. We overcome previous barriers by characterizing in greater detail over larger scales—the 65 m reservoir height at cm-m resolution—and through use of an upscaling scheme which resolves small-scale heterogeneity impacts in field-scale simulations. These models reveal that significant early time retardation of buoyantly rising CO2 plumes is followed by rapid migration under the caprock in the presence of anisotropic, layered heterogeneities. Lateral migration speeds can be enhanced by 200%, placing first-order controls on fluid flow and providing a mechanistic explanation for field observations.

Journal article

Franchini S, Krevor S, 2020, Cut, overlap and locate: a deep learning approach for the 3D localization of particles in astigmatic optical setups, EXPERIMENTS IN FLUIDS, Vol: 61, ISSN: 0723-4864

Journal article

Zahasky C, Krevor S, 2020, Global geologic carbon storage requirements of climate change mitigation scenarios, Energy & Environmental Science, Vol: 13, Pages: 1561-1567, ISSN: 1754-5692

Integrated assessment models have identified carbon capture and storage (CCS) as an important technology for limiting climate change. To achieve 2 °C climate targets, many scenarios require tens of gigatons of CO2 stored per year by mid-century. These scenarios are often unconstrained by growth rates, and uncertainty in global geologic storage assessments limits resource-based constraints. Here we show how logistic growth models, a common tool in resource assessment, provide a mathematical framework for stakeholders to monitor short-term CCS deployment progress and long-term resource requirements in the context of climate change mitigation targets. Growth rate analysis, constrained by historic commercial CO2 storage rates, indicates sufficient growth to achieve several of the 2100 storage targets identified in the assessment reports of the Intergovernmental Panel on Climate Change. A maximum global discovered storage capacity of approximately 2700 Gt is needed to meet the most aggressive targets, with this ceiling growing if CCS deployment is delayed.

Journal article

Jackson SJ, Lin Q, Krevor S, 2020, Representative Elementary Volumes, Hysteresis, and Heterogeneity in Multiphase Flow From the Pore to Continuum Scale, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397

Journal article

Zahasky C, Jackson SJ, Lin Q, Krevor Set al., 2020, Pore Network Model Predictions of Darcy-Scale Multiphase Flow Heterogeneity Validated by Experiments, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397

Journal article

Liyanage R, Russell A, Crawshaw JP, Krevor Set al., 2020, Direct experimental observations of the impact of viscosity contrast on convective mixing in a three-dimensional porous medium, Physics of Fluids, Vol: 32, Pages: 1-10, ISSN: 1070-6631

Analog fluids have been widely used to mimic the convective mixing of carbon dioxide into brine in the study of geological carbon storage. Although these fluid systems had many characteristics of the real system, the viscosity contrast between the resident fluid and the invading front was significantly different and largely overlooked. We used x-ray computed tomography to image convective mixing in a three-dimensional porous medium formed of glass beads and compared two invading fluids that had a viscosity 3.5× and 16× that of the resident fluid. The macroscopic behavior such as the dissolution rate and onset time scaled well with the viscosity contrast. However, with a more viscous invading fluid, fundamentally different plume structures and final mixing state were observed due in large part to greater dispersion.

Journal article

Kirby ME, Watson JS, Najorka J, Louvane Kenney JP, Krevor S, Weiss DJet al., 2020, Experimental study of pH effect on uranium (UVI) particle formation and transport through quartz sand in alkaline 0.1 M sodium chloride solutions, Colloids and Surfaces A: Physicochemical and Engineering Aspects, Vol: 592, Pages: 1-11, ISSN: 0927-7757

A thorough understanding of the aqueous uranium VI (UVI) chemistry in alkaline, sodium containing solutions is imperative to address a wide range of critical challenges in environmental engineering, including nuclear waste management. The aim of the present study was to characterise experimentally in more detail the control of pH on the removal of UVI from aqueous alkaline solutions through particle formation and on subsequent transport through porous media. We conducted first static batch experiments in the pH range between 10.5 and 12.5 containing 10 ppm UVI in 0.1 M NaCl solutions and examined the particles formed using filtration, dynamic light scattering, transition electron microscopy and X-ray powder diffraction. We found that at pH 10.5 and 11.5, between 75 and 96 % of UVI was removed from the solutions as clarkeite and studtite over a period of 48 h, forming particles with hydrodynamic diameters of 640 ± 111 nm and 837 ± 142 nm, respectively and representing aggregates of 10′s nm sized crystals randomly orientated. At pH 12.5, the formation of particles >0.2 μm became insignificant and no UVI was removed from solution. The mobility of UVI in these solutions was further studied using column experiments through quartz sand. We found that at pH 10.5 and 11.5, UVI containing particles were immobilised near the column inlet, likely due physical immobilisation of the particles (particle straining). At pH 12.5, however, UVI quantitatively eluted from the columns in the filter fraction <0.2 μm. The findings of our study reinforce a strong control of solution pH on particle size and U removal in alkaline solutions and subsequently on mobility of U through quartz porous media.

Journal article

Garfi G, John CM, Lin Q, Berg S, Krevor Set al., 2020, Fluid Surface Coverage Showing the Controls of Rock Mineralogy on the Wetting State, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276

Journal article

Rücker M, Bartels W-B, Bultreys T, Boone M, Singh K, Garfi G, Scanziani A, Spurin C, Krevor S, Blunt MJ, Wilson O, Mahani H, Cnudde V, Luckham PF, Georgiadis A, Berg Set al., 2020, Workflow for upscaling wettability from the nano- to core-scales, International Symposium of the Society of Core Analysts

Conference paper

Rucker M, Bartels W-B, Garfi G, Shams M, Bultreys T, Boone M, Pieterse S, Maitland GC, Krevor S, Cnudde V, Mahani H, Berg S, Georgiadis A, Luckham PFet al., 2020, Relationship between wetting and capillary pressure in a crude oil/brine/rock system: From nano-scale to core-scale, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 562, Pages: 159-169, ISSN: 0021-9797

Journal article

Krevor S, Blunt MJ, Trusler JPM, De Simone Set 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.

Book chapter

Imanovs E, Krevor S, Zadeh AM, 2020, CO2-EOR and Storage Potentials in Depleted Reservoirs in the NorwegianContinental Shelf (NCS)

© 2020 Society of Petroleum Engineers. All rights reserved. Two global challenges are an increase in carbon dioxide (CO2) concentration in the atmosphere, causingglobal warming and an increase in energy demand (UNFCCC, 2015; EIA, 2018). Carbon Capture andStorage (CCS) is believed to be a major technology to considerably reduce CO2 emissions (Budinis et al.,2018). Applying this technology, the anthropogenic CO2 could be injected into depleted reservoirs andpermanently stored in the subsurface. However, standalone CCS projects may not be economically feasibledue to CO2 separation, transportation and storage costs (Pires et al., 2011). On the other hand, one of themost efficient Enhanced Oil Recovery (EOR) methods is carbon dioxide injection (Holm, 1959). Therefore,a combination of CO2-EOR and storage schemes could offer an opportunity to produce additional oil fromdepleted reservoirs and permanently store CO2 in the subsurface in an economically efficient manner. In this study, a depleted sandstone reservoir located in the Norwegian Continental Shelf (NCS) is used. Aninnovative development scenario is considered, involving two phases: CO2 storage phase at the beginningof the project followed by a CO2-EOR phase. The objective of this paper is to evaluate the effect of differentinjection methods, including continuous gas injection (CGI), continuous water injection (CWI), WaterAlternating Gas (WAG), Tapered WAG (TWAG), Simultaneous Water Above Gas Co-injection (SWGCO),Simultaneous Water and Gas Injection (SWGI) and cyclic SWGI on oil recovery and CO2 storage potentialin the depleted reservoir. A conceptual 2D high-resolution heterogeneous model with one pair injector-producer is used toinvestigate the mechanisms taking place in the reservoir during different injection methods. This knowledgeis applied in a field scale, realistic 3D compositional reservoir model of a depleted sandstone reservoir inthe NCS including ten oil producers and twenty water/gas injectors. Th

Conference paper

Garfi G, John CM, Berg S, Krevor Set al., 2019, The sensitivity of estimates of multiphase fluid and solid properties of porous rocks to image processing, Transport in Porous Media, Vol: 131, Pages: 985-1005, ISSN: 0169-3913

X-ray microcomputed tomography (X-ray μ-CT) is a rapidly advancing technology that has been successfully employed to study flow phenomena in porous media. It offers an alternative approach to core scale experiments for the estimation of traditional petrophysical properties such as porosity and single-phase flow permeability. It can also be used to investigate properties that control multiphase flow such as rock wettability or mineral topology. In most applications, analyses are performed on segmented images obtained employing a specific processing pipeline on the greyscale images. The workflow leading to a segmented image is not straightforward or unique and, for most of the properties of interest, a ground truth is not available. For this reason, it is crucial to understand how image processing choices control properties estimation. In this work, we assess the sensitivity of porosity, permeability, specific surface area, in situ contact angle measurements, fluid–fluid interfacial curvature measurements and mineral composition to processing choices. We compare the results obtained upon the employment of two processing pipelines: non-local means filtering followed by watershed segmentation; segmentation by a manually trained random forest classifier. Single-phase flow permeability, in situ contact angle measurements and mineral-to-pore total surface area are the most sensitive properties, as a result of the sensitivity to processing of the phase boundary identification task. Porosity, interfacial fluid–fluid curvature and specific mineral descriptors are robust to processing. The sensitivity of the property estimates increases with the complexity of its definition and its relationship to boundary shape.

Journal article

Niu B, Krevor S, 2019, The Impact of Mineral Dissolution on Drainage Relative Permeability and Residual Trapping in Two Carbonate Rocks, TRANSPORT IN POROUS MEDIA, Vol: 131, Pages: 363-380, ISSN: 0169-3913

Journal article

Spurin C, Bultreys T, Bijeljic B, Blunt MJ, Krevor Set al., 2019, Mechanisms controlling fluid breakup and reconnection during two-phase flow in porous media, Physical Review E, Vol: 100, ISSN: 2470-0045

The use of Darcy's law to describe steady-state multiphase flow in porous media has been justified by the assumption that the fluids flow in continuously connected pathways. However, a range of complex interface dynamics have been observed during macroscopically steady-state flow, including intermittent pathway flow where flow pathways periodically disconnect and reconnect. The physical mechanisms controlling this behavior have remained unclear, leading to uncertainty concerning the occurrence of the different flow regimes. We observe that the fraction of intermittent flow pathways is dependent on the capillary number and viscosity ratio. We propose a phase diagram within this parameter space to quantify the degree of intermittent flow.

Journal article

Spurin C, Bultreys T, Bijeljic B, Blunt MJ, Krevor Set al., 2019, Intermittent fluid connectivity during two-phase flow in a heterogeneous carbonate rock, Physical Review E, Vol: 100, ISSN: 2470-0045

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 modeling 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. Little is known about the pore structure controls or the impact of intermittency on continuum scale flow properties. Here we investigate the impact of intermittent pathways on the connectivity of the fluids for a carbonate rock. Using laboratory-based micro computed tomography imaging we observe that intermittent pathway flow occurs in intermediate-sized pores due to the competition between both flowing fluids. This competition moves to smaller pores when the flow rate of the nonwetting phase increases. Intermittency occurs in poorly connected pores or in regions where the nonwetting phase itself is poorly connected. Intermittent pathways lead to the interrupted transport of the fluids; this means they are important in determining continuum scale flow properties, such as relative permeability. The impact of intermittency on flow properties is significant because it occurs at key locations, whereby the nonwetting phase is otherwise disconnected.

Journal article

De Simone S, Jackson SJ, Krevor S, 2019, The error in using superposition to estimate pressure during multi‐site subsurface CO 2 storage, Geophysical Research Letters, Vol: 46, Pages: 6525-6533, ISSN: 0094-8276

Analytic pressure estimates for multisite CO2 injection are typically performed through the superposition of single‐site injection models. This is theoretically invalid for multiphase flow because of its nonlinearity. We quantify the error associated with the application of superposition in scenarios with sites located in a rectangular grid geometry. We show that the use of superposition results in overestimates of the pressure buildup, because it neglects the presence of multiple CO2 plumes, which increase the reservoir fluid mobility. The adoption of a dimensionless time scaled to the geometric average between the advective and diffusive characteristic times allows us to define a general model for the maximum error, which may be used to evaluate the validity of using superposition, or to correct the pressure estimates when errors are significant. This procedure can be applied to any analytical solution and advances the extension of single‐well models to scenarios of multiple injection sites.

Journal article

Lin Q, Bijeljic B, Berg S, Pini R, Blunt MJ, Krevor Set al., 2019, Minimal surfaces in porous media: Pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone, Physical Review E, Vol: 99, Pages: 063105-1-063105-13, ISSN: 1539-3755

High-resolution x-ray imaging was used in combination with differential pressure measurements to measurerelative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on asample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil toalter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flowrate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, x-raytomographic images were taken. The images were used to compute saturation, interfacial area, curvature, andcontact angle. From this information relative permeability and capillary pressure were determined as functionsof saturation. We compare our results with a previously published experiment under water-wet conditions. Theoil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, ofapproximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock.The capillary pressure was slightly negative and 10 times smaller in magnitude than for the water-wet rock,and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area wasalso largely constant in this saturation range. The measured static contact angles had an average of 80◦ with astandard deviation of 17◦. We observed that the oil-brine interfaces were not flat, as may be expected for a verylow mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. Theseinterfaces were approximately minimal surfaces, which implies well-connected phases. Saddle-shaped menisciswept through the pore space at a constant capillary pressure and with an almost fixed area, removing most ofthe oil.

Journal article

Veillard C, John C, Krevor S, Najorka Jet al., 2019, Rock-buffered recrystallization of Marion Plateau dolomites at low temperature evidenced by clumped isotope thermometry and X-Ray diffraction analysis, Geochimica et Cosmochimica Acta, Vol: 252, Pages: 190-212, ISSN: 0016-7037

Much debate exists on the extent to which early dolomites recrystallize and preserve the signature of their primary diagenetic setting. Here, we combine clumped isotopes thermometry with X-ray diffraction and thin section petrography to study dolomite recrystallization under shallow burial (<1 km) conditions. We analysed 26 dolomite samples from two Miocene carbonate platforms on the Marion Plateau, NE Australia. Marion Plateau dolomites provide an ideal case study to examine the effects of recrystallization because of the relative simplicity of the geological setting, with simple subsidence, and several episodes of early dolomitization by normal Miocene sea water. Results show that Marion Plateau dolomites are very rich in calcium and their formation temperature inferred from clumped isotopes T(Δ47dol) ranges between 12 and 35°C. The apparent fluid composition (δ18Ow (app)) falls in the range of sea water composition, but a correlation between T(Δ47dol), δ18Odol, and δ18Ow (app) exists: the higher the crystallization temperature, the more negative the fluid composition is. T(Δ47dol) and δ18Ow (app) increase with depth, whereas δ18Odol and δ13Cdol tend to both decrease with depth. We interpret the negative correlation between T(Δ47dol) and δ18Ow (app) as evidence of shallow burial recrystallization via dissolution/re-precipitation. Modelling of the T(Δ47dol), δ18Odol, and δ18Ow (app) indicates that the recrystallization happened at very low water to rock ratio. Carbon isotopes are inherited from the dolomitization process, and not reset during recrystallization. This study shows that dolomite recrystallization has the potential to affect T(Δ47dol) at depths shallower than previously demonstrated. It emphasizes the fact that high calcium dolomites (and possibly aragonite and high Mg-calcite) can have a range of T(Δ47dol) before entering the solid-state reordering re

Journal article

Lin Q, Bijeljic B, Krevor SC, Blunt MJ, Rücker M, Berg S, Coorn A, Van Der Linde H, Georgiadis A, Wilson OBet al., 2019, A New Waterflood Initialization Protocol With Wettability Alteration for Pore-Scale Multiphase Flow Experiments, Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description, Vol: 60, Pages: 264-272, ISSN: 1529-9074

Journal article

Jackson SJ, Krevor S, 2019, Characterization of hysteretic multiphase flow from the mm to m scale in heterogeneous rocks, The 32nd International Symposium of the Society of Core Analysts, Publisher: EDP Sciences, ISSN: 2267-1242

Incorporating mm-m scale capillary pressure heterogeneity into upscaled numerical models is key to the successful prediction of low flow potential plume migration and trapping at the field scale. Under such conditions, the upscaled, equivalent relative permeability incorporating capillary pressure heterogeneity is far from that derived conventionally at the viscous limit, dependent on the heterogeneity structure and flow rate, i.e. dependent on the capillary number. Recent work at the SCA 2017 symposium (SCA2017-022) demonstrated how equivalent functions can be obtained on heterogeneous rock cores from the subsurface under drainage conditions; going beyond traditional SCAL. Experimental observations using medical CT scanning can be combined with numerical modelling so that heterogeneous subsurface rock cores can be directly characterized and used to populate field scale reservoir models. In this work, we extend this characterization approach by incorporating imbibition cycles into the methodology. We use a Bunter sandstone core with several experimental CO 2 -Brine core flood datasets at different flow rates (2x drainage, 1x imbibition and 2x trapping) to demonstrate the characterization of hysteretic multiphase flow functions in water-wet rocks. We show that mm-m scale experimental saturations and equivalent, low flow potential relative permeabilities can be predicted during drainage and imbibition, along with trapping characteristics. Equivalent imbibition relative permeabilities appear as a function of capillary number, as in the drainage cases. We also find that the form of capillary pressure function during imbibition has a large impact on the trapping characteristics, with local heterogeneity trapping reduced (or removed), if the capillary pressure drops to zero, or below at the residual saturation.

Conference paper

Lin Q, Bijeljic B, Berg S, Pini R, Blunt MJ, Krevor Set al., 2019, Minimal surfaces in porous media: pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone, Publisher: EarthArXiv

We observed features of pore scale fluid distributions during oil-brine displacement in a mixed-wet sandstone rock sample. High-resolution X-ray imaging was used in combination with differential pressure measurements to measure relative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on a sample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil to alter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flow rate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, X-ray tomographic images were taken. The images were used to compute saturation, interfacial area, curvature and contact angle. From this information relative permeability and capillary pressure were determined as functions of saturation. We compare our results with a previously published experiment with strongly water-wet conditions. The oil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, of approximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock. The capillary pressure was slightly negative and ten times smaller in magnitude than a similar water-wet rock, and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area was also largely constant in this saturation range. The measured static contact angles had an average of $80^{\circ}$ with a standard deviation of $17^{\circ}$.We observed that the oil-brine interfaces were not flat, as may be expected for a very low mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. These interfaces were approximately minimal surfaces which allow efficient displacement and imply well-connected phases. Saddle-shaped menisci swept through the pore space at a constant capillary

Working paper

Franchini S, Charogiannis A, Markides CN, Blunt MJ, Krevor Set al., 2019, Calibration of astigmatic particle tracking velocimetry based on generalized Gaussian feature extraction, Advances in Water Resources, Vol: 124, Pages: 1-8, ISSN: 0309-1708

Flow and transport in porous media are driven by pore scale processes. Particle tracking in transparent porous media allows for the observation of these processes at the time scale of ms. We demonstrate an application of defocusing particle tracking using brightfield illumination and a CMOS camera sensor. The resulting images have relatively high noise levels. To address this challenge, we propose a new calibration for locating particles in the out-of-plane direction. The methodology relies on extracting features of particle images by fitting generalized Gaussian distributions to particle images. The resulting fitting parameters are then linked to the out-of-plane coordinates of particles using flexible machine learning tools. A workflow is presented which shows how to generate a training dataset of fitting parameters paired to known out-of-plane locations. Several regression models are tested on the resulting training dataset, of which a boosted regression tree ensemble produced the lowest cross-validation error. The efficiacy of the proposed methodology is then examined in a laminar channel flow in a large measurement volume of 2048, 1152 and 3000 μm in length, width and depth respectively. The size of the test domain reflects the representative elementary volume of many fluid flow phenomena in porous media. Such large measurement depths require the collection of images at different focal levels. We acquired images at 21 focal levels 150 μm apart from each other. The error in predicting the out-of-plane location in a single slice of 240 μm thickness was found to be 7 μm, while in-plane locations were determined with sub-pixel resolution (below 0.8 μm). The mean relative error in the velocity measurement was obtained by comparing the experimental results to an analytic model of the flow. The estimated displacement errors in the axial direction of the flow were 0.21 pixel and 0.22 pixel at flows rates of 1.0 mL/h and 2.5 mL/h, respectively. These resu

Journal article

Liyanage R, Cen J, Krevor S, Crawshaw J, Pini Ret al., 2019, Multidimensional observations of dissolution-driven convection in simple porous media using X-ray CT scanning, Transport in Porous Media, Vol: 126, Pages: 355-378, ISSN: 0169-3913

We present an experimental study of dissolution-driven convection in a three-dimensional porous medium formed from a dense random packing of glass beads. Measurements are conducted using the model fluid system MEG/water in the regime of Rayleigh numbers, Ra=2000−5000. X-ray computed tomography is applied to image the spatial and temporal evolution of the solute plume non-invasively. The tomograms are used to compute macroscopic quantities including the rate of dissolution and horizontally averaged concentration profiles, and enable the visualisation of the flow patterns that arise upon mixing at a spatial resolution of about (2×2×2)mm3. The latter highlights that under this Ra regime convection becomes truly three-dimensional with the emergence of characteristic patterns that closely resemble the dynamical flow structures produced by high-resolution numerical simulations reported in the literature. We observe that the mixing process evolves systematically through three stages, starting from pure diffusion, followed by convection-dominated and shutdown. A modified diffusion equation is applied to model the convective process with an onset time of convection that compares favourably with the literature data and an effective diffusion coefficient that is almost two orders of magnitude larger than the molecular diffusivity of the solute. The comparison of the experimental observations of convective mixing against their numerical counterparts of the purely diffusive scenario enables the estimation of a non-dimensional convective mass flux in terms of the Sherwood number, Sh=0.025Ra. We observe that the latter scales linearly with Ra, in agreement with both experimental and numerical studies on thermal convection over the same Ra regime.

Journal article

Budinis S, Krevor S, Mac Dowell N, Brandon N, Hawkes Aet al., 2018, An assessment of CCS costs, barriers and potential, Energy Strategy Reviews, Vol: 22, Pages: 61-81, ISSN: 2211-467X

© 2018 Elsevier Ltd Global decarbonisation scenarios include Carbon Capture and Storage (CCS) as a key technology to reduce carbon dioxide (CO2) emissions from the power and industrial sectors. However, few large scale CCS plants are operating worldwide. This mismatch between expectations and reality is caused by a series of barriers which are preventing this technology from being adopted more widely. The goal of this paper is to identify and review the barriers to CCS development, with a focus on recent cost estimates, and to assess the potential of CCS to enable access to fossil fuels without causing dangerous levels of climate change. The result of the review shows that no CCS barriers are exclusively technical, with CCS cost being the most significant hurdle in the short to medium term. In the long term, CCS is found to be very cost effective when compared with other mitigation options. Cost estimates exhibit a high range, which depends on process type, separation technology, CO2transport technique and storage site. CCS potential has been quantified by comparing the amount of fossil fuels that could be used globally with and without CCS. In modelled energy system transition pathways that limit global warming to less than 2 °C, scenarios without CCS result in 26% of fossil fuel reserves being consumed by 2050, against 37% being consumed when CCS is available. However, by 2100, the scenarios without CCS have only consumed slightly more fossil fuel reserves (33%), whereas scenarios with CCS available end up consuming 65% of reserves. It was also shown that the residual emissions from CCS facilities is the key factor limiting long term uptake, rather than cost. Overall, the results show that worldwide CCS adoption will be critical if fossil fuel reserves are to continue to be substantively accessed whilst still meeting climate targets.

Journal article

Lin Q, Bijeljic B, Pini R, Blunt MJ, Krevor SCet al., 2018, Imaging and measurement of pore‐scale interfacial curvature to determine capillary pressure simultaneously with relative permeability, Water Resources Research, Vol: 54, Pages: 7046-7060, ISSN: 0043-1397

There are a number of challenges associated with the determination of relative permeability and capillary pressure. It is difficult to measure both parameters simultaneously on the same sample using conventional methods. Instead, separate measurements are made on different samples, usually with different flooding protocols. Hence, it is not certain that the pore structure and displacement processes used to determine relative permeability are the same as those when capillary pressure was measured. Moreover, at present, we do not use pore‐scale information from high‐resolution imaging to inform multiphase flow properties directly. We introduce a method using pore‐scale imaging to determine capillary pressure from local interfacial curvature. This, in combination with pressure drop measurements, allows both relative permeabilities and capillary pressure to be determined during steady state coinjection of two phases through the core. A steady state waterflood experiment was performed in a Bentheimer sandstone, where decalin and brine were simultaneously injected through the core at increasing brine fractional flows from 0 to 1. The local saturation and the curvature of the oil‐brine interface were determined. Using the Young‐Laplace law, the curvature was related to a local capillary pressure. There was a detectable gradient in both saturation and capillary pressure along the flow direction. The relative permeability was determined from the experimentally measured pressure drop and average saturation obtained by imaging. An analytical correction to the brine relative permeability could be made using the capillary pressure gradient. The results for both relative permeability and capillary pressure are consistent with previous literature measurements on larger samples.

Journal article

Kirby M, Simperler A, Krevor S, Weiss D, Sonnenberg Jet al., 2018, Computational tools for calculating log β values of geochemically relevant uranium organometallic complexes, Journal of Physical Chemistry A, Vol: 122, Pages: 8007-8019, ISSN: 1089-5639

Uranium (UVI) interacts with organic ligands, subsequently controlling its aqueous chemistry. It is therefore imperative to assess the binding ability of natural organic molecules. We evidence that density functional theory (DFT) can be used as a practical protocol for predicting the stability of UVI organic ligand complexes, allowing for the development of a relative stability series for organic complexes with limited experimental data. Solvation methods and DFT settings were benchmarked to suggest a suitable off-the-shelf solution. The results indicate that the IEFPCM solvation method should be employed. A mixed solvation approach improves the accuracy of the calculated stability constant (log β); however, the calculated log β are approximately five times more favorable than experimental data. Different basis sets, functionals, and effective core potentials were tested to check that there were no major changes in molecular geometries and ΔrG. The recommended method employed is the B3LYP functional, aug-cc-pVDZ basis set for ligands, MDF60 ECP and basis set for UVI, and the IEFPCM solvation model. Using the fitting approach employed in the literature with these updated DFT settings allows fitting of 1:1 UVI complexes with root-mean-square deviation of 1.38 log β units. Fitting multiple bound carboxylate ligands indicates a second, separate fitting for 1:2 and 1:3 complexes.

Journal article

Sonnenberg J, Kirby M, Simperler A, Krevor S, Weiss Det al., 2018, Towards stability constant prediction in uranium siderophore complexes, 256th National Meeting and Exposition of the American-Chemical-Society (ACS) - Nanoscience, Nanotechnology and Beyond, Publisher: AMER CHEMICAL SOC, ISSN: 0065-7727

Conference paper

Muggeridge AH, Alshawaf M, Krevor S, 2018, Experimental Investigation of Cross-flow in Stratified Reservoirs During Polymer Flooding, SPE IMproved Oil Recovery Conference

Conference paper

Jackson S, Agada S, Reynolds C, Krevor SCet al., 2018, Characterizing drainage multiphase flow in heterogeneous sandstones, Water Resources Research, Vol: 54, Pages: 3139-3161, ISSN: 0043-1397

In this work, we analyze the characterization of drainage multiphase flow properties on heterogeneous rock cores using a rich experimental data set and mm‐m scale numerical simulations. Along with routine multiphase flow properties, 3‐D submeter scale capillary pressure heterogeneity is characterized by combining experimental observations and numerical calibration, resulting in a 3‐D numerical model of the rock core. The uniqueness and predictive capability of the numerical models are evaluated by accurately predicting the experimentally measured relative permeability of N2—DI water and CO2—brine systems in two distinct sandstone rock cores across multiple fractional flow regimes and total flow rates. The numerical models are used to derive equivalent relative permeabilities, which are upscaled functions incorporating the effects of submeter scale capillary pressure. The functions are obtained across capillary numbers which span four orders of magnitude, representative of the range of flow regimes that occur in subsurface CO2 injection. Removal of experimental boundary artifacts allows the derivation of equivalent functions which are characteristic of the continuous subsurface. We also demonstrate how heterogeneities can be reorientated and restructured to efficiently estimate flow properties in rock orientations differing from the original core sample. This analysis shows how combined experimental and numerical characterization of rock samples can be used to derive equivalent flow properties from heterogeneous rocks.

Journal article

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