Publications
544 results found
Saif T, Lin Q, Gao Y, et al., 2019, 4D in situ synchrotron X-ray tomographic microscopy and laser-based heating study of oil shale pyrolysis, Applied Energy, Vol: 235, Pages: 1468-1475, ISSN: 0306-2619
The comprehensive characterization and analysis of the evolution of micro-fracture networks in oil shales during pyrolysis is important to understand the complex petrophysical changes during hydrocarbon recovery. We used time-resolved X-ray microtomography to perform pore-scale dynamic imaging with a synchrotron light source to capture in 4-D (three-dimensional image + real time) the evolution of fracture initiation, growth, coalescence and closure. A laser-based heating system was used to pyrolyze a sample of Eocene Green River (Mahogany Zone) up to 600 °C with tomograms acquired every 30 s at 1.63 µm computed voxel size and analyzed using Digital Volume Correlation (DVC) for full 3-D strain and deformation maps. At 354 °C the first isolated micro-fractures were observed and by 378 °C, a connected fracture network was formed as the solid organic matter was transformed into volatile hydrocarbon components. With increasing temperature, we observed simultaneous pore space growth and coalescence as well as temporary closure of minor fractures caused by local compressive stresses. This indicates that the evolution of individual fractures not only depends on organic matter composition but also on the dynamic development of neighboring fractures. Our results demonstrate that combining synchrotron X-ray tomography, laser-based heating and DVC provides a powerful methodology for characterizing dynamics of multi-scale physical changes during oil shale pyrolysis to help optimize hydrocarbon recovery.
Franchini S, Charogiannis A, Markides CN, et 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
Dipankar D, Nasser AK, Kishore PR, et al., 2019, Two-phase fluid flow behaviour of minagish ooilte dynamic rock types and their impact on reservoir management practices
Nine capillary constrained pore facies have been used to characterize the static rock types of the Minagish Oolite reservoir. However, this classification resulted poor history match on dynamic platform. An in-depth review indicated that two representative textural facies - connected vuggy limestone and fractured limestone - were not captured in the model due to either non-availability of suitable plug samples or respective bed thickness below log resolution. To resolve this issue, high resolution X-ray tomographic whole core data was generated in order to capture continuous pore network records along a 337ft core section. Using CT based pore typing, six representative dynamic rock types were created with 10 cm vertical resolution. Out of these, two are vug/fracture dominated high permeability type and three are matrix pore dominated rock types. One is tight and non-reservoir facies. The high-permeability connected vuggy or fractured limestone samples show a wide range of pore size. Under weakly oil-wet conditions, the relative permeabilities of these rock types indicate unfavorable waterflood performance and only the oil from the vugs or fractures could be recovered in a full field dynamic setting. In case of grainstones with separate vug porosity, the non-connected vugs are connected through the macropore system. After drainage of the macropore and vugs, the micropores get invaded, which contributes well to the changes in saturation profile. In fractured limestone, in particular, the connected fractures control the fluid flow behavior, which has extremely low waterflood relative permeability cross-over saturation of 0.11. This indicates a very unfavorable oil recovery where essentially only the oil in the fractures can be displaced. Wettability variations from strongly oil-wet to mixed-wet conditions had little impact on likely recovery and the overall assessment of waterflood behavior. The scanning curves, representing waterflooding a transition zone, again displ
Al-Khalifa N, Dutta D, Arora D, et al., 2019, Characterization of megascopic, connected vuggy limestone through whole core tomography - A useful tool to capture high resolution reservoir properties
Reservoir data generated in the laboratory is often deceptive due to unwarranted sampling errors. Sometimes, it is not possible to sample from a representative rock type, if the size of the rock framework or pore body is bigger than the 1.5” core plug size. Error may also be introduced in case of multiple rock types at the lamina scale being combined within a plug sample. Multi-scale imaging through X-Ray tomography is a good solution to these problems. CT image statistical parameters like - mean lightness (L values) and standard deviation of mean lightness (STDEV) in combination with wireline logs (NPHI) can successfully be used to classify different rock and pore types within a heterogeneous core. Hydraulic conductivity simulations can lead to decipher connectivity of pores within it. Plug samples from representative rock types can subsequently be used for producing high-resolution, multi-scale 2D and 3D images. Numerical simulations are performed on these images to generate petrophysical properties and two-phase fluid flow properties for each individual rock type. This technique is applied to a Cretaceous rudist limestone section of Minagish Oolite reservoir and successfully captured data for a high permeability, megascopic, connected vuggy rudist limestone, which was otherwise not possible to characterize through standard routine and special core analysis. Key words: Vuggy limestone, high permeability, X-Ray tomography, Minagish Oolite.
AlSofi AM, Blunt MJ, 2019, The decomposition of volumetric sweep efficiency and its utility
The traditional definition of volumetric sweep efficiency sums the effects of both fingering (arising due to contrasts in mobility) and bypassing (arising due to contrasts in permeability as well as well placement). Accordingly, we cannot quantitatively attribute poor sweep to either bypassing or fingering. Similarly, in EOR, the incremental recovery cannot be quantitatively associated with the reduction of those effects. For such purposes, we rely on visualization and mapping of saturation profiles to quantify and characterize the remaining oil in place including its distribution. . In this work, we propose a complementary method to obtain an instantaneous insight of the remaining oil distribution. We demonstrate the decomposition of fingering and bypassing effects and its utility. We first redefine recovery factors such that we decouple bypassing and fingering effects. We then validate those redefined sweep indicators by examining a 5-spot waterflood and two idealistic polymer floods. Later, we demonstrate the possible utility of those redefined sweep indicators through different examples. In one example, we compare the performance of a shear - thinning polymer to a recovery-equivalent Newtonian polymer. Using fingering and bypassing sweep indicators, we can immediately conclude that the shear-thinning polymer exacerbates bypassing. We recommend the adoption of our redefined sweep indicators in any simulation suite. They provide instant understanding of sweep and hence can be complementary to standard practices of oil saturation mapping and of special value when analyzing the results of multiple realizations and/or development scenarios.
AlSofi AM, Blunt MJ, 2019, The decomposition of volumetric sweep efficiency and its utility
Copyright 2019, Society of Petroleum Engineers. The traditional definition of volumetric sweep efficiency sums the effects of both fingering (arising due to contrasts in mobility) and bypassing (arising due to contrasts in permeability as well as well placement). Accordingly, we cannot quantitatively attribute poor sweep to either bypassing or fingering. Similarly, in EOR, the incremental recovery cannot be quantitatively associated with the reduction of those effects. For such purposes, we rely on visualization and mapping of saturation profiles to quantify and characterize the remaining oil in place including its distribution. . In this work, we propose a complementary method to obtain an instantaneous insight of the remaining oil distribution. We demonstrate the decomposition of fingering and bypassing effects and its utility. We first redefine recovery factors such that we decouple bypassing and fingering effects. We then validate those redefined sweep indicators by examining a 5-spot waterflood and two idealistic polymer floods. Later, we demonstrate the possible utility of those redefined sweep indicators through different examples. In one example, we compare the performance of a shear - thinning polymer to a recovery-equivalent Newtonian polymer. Using fingering and bypassing sweep indicators, we can immediately conclude that the shear-thinning polymer exacerbates bypassing. We recommend the adoption of our redefined sweep indicators in any simulation suite. They provide instant understanding of sweep and hence can be complementary to standard practices of oil saturation mapping and of special value when analyzing the results of multiple realizations and/or development scenarios.
AlSofi AM, Blunt MJ, 2019, The decomposition of volumetric sweep efficiency and its utility
Copyright 2019, Society of Petroleum Engineers. The traditional definition of volumetric sweep efficiency sums the effects of both fingering (arising due to contrasts in mobility) and bypassing (arising due to contrasts in permeability as well as well placement). Accordingly, we cannot quantitatively attribute poor sweep to either bypassing or fingering. Similarly, in EOR, the incremental recovery cannot be quantitatively associated with the reduction of those effects. For such purposes, we rely on visualization and mapping of saturation profiles to quantify and characterize the remaining oil in place including its distribution. . In this work, we propose a complementary method to obtain an instantaneous insight of the remaining oil distribution. We demonstrate the decomposition of fingering and bypassing effects and its utility. We first redefine recovery factors such that we decouple bypassing and fingering effects. We then validate those redefined sweep indicators by examining a 5-spot waterflood and two idealistic polymer floods. Later, we demonstrate the possible utility of those redefined sweep indicators through different examples. In one example, we compare the performance of a shear - thinning polymer to a recovery-equivalent Newtonian polymer. Using fingering and bypassing sweep indicators, we can immediately conclude that the shear-thinning polymer exacerbates bypassing. We recommend the adoption of our redefined sweep indicators in any simulation suite. They provide instant understanding of sweep and hence can be complementary to standard practices of oil saturation mapping and of special value when analyzing the results of multiple realizations and/or development scenarios.
AlSofi AM, Blunt MJ, 2019, The decomposition of volumetric sweep efficiency and its utility
Copyright 2019, Society of Petroleum Engineers. The traditional definition of volumetric sweep efficiency sums the effects of both fingering (arising due to contrasts in mobility) and bypassing (arising due to contrasts in permeability as well as well placement). Accordingly, we cannot quantitatively attribute poor sweep to either bypassing or fingering. Similarly, in EOR, the incremental recovery cannot be quantitatively associated with the reduction of those effects. For such purposes, we rely on visualization and mapping of saturation profiles to quantify and characterize the remaining oil in place including its distribution. . In this work, we propose a complementary method to obtain an instantaneous insight of the remaining oil distribution. We demonstrate the decomposition of fingering and bypassing effects and its utility. We first redefine recovery factors such that we decouple bypassing and fingering effects. We then validate those redefined sweep indicators by examining a 5-spot waterflood and two idealistic polymer floods. Later, we demonstrate the possible utility of those redefined sweep indicators through different examples. In one example, we compare the performance of a shear - thinning polymer to a recovery-equivalent Newtonian polymer. Using fingering and bypassing sweep indicators, we can immediately conclude that the shear-thinning polymer exacerbates bypassing. We recommend the adoption of our redefined sweep indicators in any simulation suite. They provide instant understanding of sweep and hence can be complementary to standard practices of oil saturation mapping and of special value when analyzing the results of multiple realizations and/or development scenarios.
Lin Q, Alhammadi AM, Gao Y, et al., 2019, Iscal for complete rock characterization: Using pore-scale imaging to determine relative permeability and capillary pressure
We combine steady-state measurements of relative permeability with pore-scale imaging to estimate local capillary pressure. High-resolution three-dimensional X-ray tomography enables the pore structure and fluid distribution to be quantified at reservoir temperatures and pressures with a resolution of a few microns. Two phases are injected through small cylindrical samples at a series of fractional flows until the pressure differential across the core is constant. Then high-quality images are acquired from which saturation is calculated, using differential imaging to quantify the phase distributions in micro-porosity which cannot be explicitly resolved. The relative permeability is obtained from the pressure drop and fractional flow, as in conventional measurements. The curvature of the fluid/fluid interfaces in the larger pore spaces is found, then from the Young-Laplace equation, the capillary pressure is calculated. In addition, the sequence of images of fluid distribution captures the displacement process. Observed gradients in capillary pressure - the capillary end effect - can be accounted for analytically in the calculation of relative permeability. We illustrate our approach with three examples of increasing complexity. First, we compare the measured relative permeability and capillary pressure for Bentheimer sandstone, both for a clean sample and a mixed-wet core that had been aged in reservoir crude oil after centrifugation. We characterize the distribution of contact angles to demonstrate that the mixed-wet sample has a wide range of angle centred, approximately, on 90°. We then study a water-wet micro-porous carbonate to illustrate the impact of sub-resolution porosity on the flow behaviour: here oil, as the non-wetting phase, is present in both the macro-pores and micro-porosity. Finally, we present results for a mixed-wet reservoir carbonate. We show that the oil/water interfaces in the mixed-wet samples are saddle-shaped with two opposite, but alm
Mosser L, Dubrule O, Blunt MJ, 2019, Deep stochastic inversion
Numerous geophysical tasks require the solution of ill-posed inverse problems where we seek to find a distribution of earth models that match observed data such as reflected acoustic waveforms or produced hydrocarbon volumes. We present a framework to create stochastic samples of posterior property distributions for ill-posed inverse problems using a gradient-based approach. The spatial distribution of petrophysical properties is created by a deep generative model and controlled by a set of latent variables. A generative adversarial network (GAN) is used to represent a prior distribution of geological models based on a training set of object-based models. We minimize the mismatch between observed ground-truth data and numerical forward-models of the generator output by first computing gradients of the objective function with respect to grid-block properties and using neural network backpropagation to obtain gradients with respect to the latent variables. Synthetic test cases of acoustic waveform inversion and reservoir history matching are presented. In seismic inversion, we use a Metropolis adjusted Langevin algorithm (MALA) to obtain posterior samples. For both synthetic cases, we show that deep generative models such as GANs can be combined in an end-to-end framework to obtain stochastic solutions to geophysical inverse problems.
Leu L, Bertier P, Georgiadis A, et al., 2019, SAXS and WAXS microscopy applied to mudrocks: A new method for systematic multiscale studies of porosity, pore orientation and mineralogy
We apply scanning SAXS and WAXS microscopy to different mudrock samples. The method characterizes the microstructure in terms of porosity and preferential pore alignment of small pores 6 -202 nm size. These small features are experimentally challenging to resolve for statistically relevant sample volumes with state of the art characterization techniques, such as imaging methods. A key novelty in this study is the quantification of the mineralogy and mineral phase content from the WAXS measurements. Thus, a detailed quantification and comparison of important microstructural parameters is achieved. The method is used in a raster scanning mode, where thousands of consecutive measurements are performed, with a high micrometric spatial resolution, over mm sized sample areas. Therefore, simultaneously the variation of the microstructure is resolved on the pore and lamina scale. We propose to use scanning SAXS-WAXS microcopy in future studies for investigations of the systematic relationships between mineralogy and the pore network.
Dipankar D, Nasser AK, Kishore PR, et al., 2019, Two-phase fluid flow behaviour of minagish ooilte dynamic rock types and their impact on reservoir management practices
Nine capillary constrained pore facies have been used to characterize the static rock types of the Minagish Oolite reservoir. However, this classification resulted poor history match on dynamic platform. An in-depth review indicated that two representative textural facies - connected vuggy limestone and fractured limestone - were not captured in the model due to either non-availability of suitable plug samples or respective bed thickness below log resolution. To resolve this issue, high resolution X-ray tomographic whole core data was generated in order to capture continuous pore network records along a 337ft core section. Using CT based pore typing, six representative dynamic rock types were created with 10 cm vertical resolution. Out of these, two are vug/fracture dominated high permeability type and three are matrix pore dominated rock types. One is tight and non-reservoir facies. The high-permeability connected vuggy or fractured limestone samples show a wide range of pore size. Under weakly oil-wet conditions, the relative permeabilities of these rock types indicate unfavorable waterflood performance and only the oil from the vugs or fractures could be recovered in a full field dynamic setting. In case of grainstones with separate vug porosity, the non-connected vugs are connected through the macropore system. After drainage of the macropore and vugs, the micropores get invaded, which contributes well to the changes in saturation profile. In fractured limestone, in particular, the connected fractures control the fluid flow behavior, which has extremely low waterflood relative permeability cross-over saturation of 0.11. This indicates a very unfavorable oil recovery where essentially only the oil in the fractures can be displaced. Wettability variations from strongly oil-wet to mixed-wet conditions had little impact on likely recovery and the overall assessment of waterflood behavior. The scanning curves, representing waterflooding a transition zone, again displ
Akai T, Alhammadi AM, Blunt MJ, et al., 2019, Direct multiphase numerical simulation on mixed-wet reservoir carbonates
To better understand local displacement efficiency, direct numerical simulations of water-flooding in a mixed-wet rock from a producing reservoir were performed using the multiphase Lattice Boltzmann (LB) method. Experimentally measured contact angles (AlRatrout et al., 2017) were incorporated into the simulation models using our previously reported wetting boundary condition for the LB method (Akai et al., 2018b). The simulation model was calibrated by comparing pore occupancy and fluid conductivity with results from an experimental water-flooding study where the fluid configurations were imaged at a resolution of a few microns (Alhammadi et al., 2017, 2018). Furthermore, to investigate the impact of several enhanced oil recovery (EOR) schemes on recovery, the calibrated simulation model was also used for a sensitivity study. Taking the calibrated model as a base case, three EOR cases were investigated; low salinity water-flooding, surfactant flooding and polymer flooding. For low salinity water-flooding, the wettability of pore walls was changed to be more water-wet than that of the base case. For surfactant flooding, the interfacial tension was reduced. For polymer flooding, the viscosity of injection water was increased. A significant change in oil recovery factor was observed in these cases. These results make it possible to better understand the impact of EOR schemes on microscopic recovery. We demonstrate the predictive power of our direct numerical simulation by presenting comparisons of the fluid distribution at the pore-scale between the experiment and simulation. Then, we show how direct numerical simulation helps understand EOR schemes. This work provides a comprehensive workflow for pore-scale modeling from experiments to modeling.
Scanziani A, Alhammadi A, Bijeljic B, et al., 2019, Three-phase flow visualization and characterization for a mixed-wet carbonate rock
A novel method is presented to characterise in situ three-phase flow, including wettability, pore occupancy and displacement mechanisms, at the pore scale. We used X-ray microtomography to obtain 3D images of a carbonate reservoir rock saturated with crude oil and formation brine at subsurface conditions. The sample had been aged with crude oil from the same reservoir to replicate the sunsurface wetting conditions. The pore occupancy analysis shows that brine is non-wetting to oil and gas is non-wetting to brine with a wettability order of oil-brine-gas from the most to the least wetting fluid. The waterflood recovery after 1 pore volume injected was only 14%, but this increased to 48% after further gas injection. New multiple displacement mechanisms were observed, with gas displacing brine, which in turn displaces oil. The results from this work can be used to improve the prediction accuracy of the three-phase network models and helps in the design of gas injection processes.
Singh K, Menke H, Andrew M, et al., 2018, Timeresolved synchrotron X-ray micro-tomography datasets of drainage and imbibition in carbonate rocks, Scientific Data, Vol: 5, ISSN: 2052-4463
Multiphase flow in permeable media is a complex pore-scale phenomenon, which is important in many natural and industrial processes. To understand the pore-scale dynamics of multiphase flow, we acquired time-series synchrotron X-ray micro-tomographic data at a voxel-resolution of 3.28 μm and time-resolution of 38 s during drainage and imbibition in a carbonate rock, under a capillary-dominated flow regime at elevated pressure. The time-series data library contains 496 tomographic images (gray-scale and segmented) for the complete drainage process, and 416 tomographic images (gray-scale and segmented) for the complete imbibition process. These datasets have been uploaded on the publicly accessible British Geological Survey repository, with the objective that the time-series information can be used by other groups to validate pore-scale displacement models such as direct simulations, pore-network and neural network models, as well as to investigate flow mechanisms related to the displacement and trapping of the non-wetting phase in the pore space. These datasets can also be used for improving segmentation algorithms for tomographic data with limited projections.
Singh K, Anabaraonye BU, Blunt MJ, et al., 2018, Partial dissolution of carbonate rock grains during reactive CO<inf>2</inf>-saturated brine injection under reservoir conditions, Advances in Water Resources, Vol: 122, Pages: 27-36, ISSN: 0309-1708
One of the major concerns of carbon capture and storage (CCS) projects is the prediction of the long-term storage security of injected CO2. When injected underground in saline aquifers or depleted oil and gas fields, CO2mixes with the resident brine to form carbonic acid. The carbonic acid can react with the host carbonate rock, and alter the rock structure and flow properties. In this study, we have used X-ray micro-tomography and focused ion beam scanning electron microscopy (FIB-SEM) techniques to investigate the dissolution behavior in wettability-altered carbonate rocks at the nm- to µm-scale, to investigate CO2storage in depleted oil fields that have oil-wet or mixed-wet conditions. Our novel procedure of injecting oil after reactive transport has revealed previously unidentified (ghost) regions of partially-dissolved rock grains that were difficult to identify in X-ray tomographic images after dissolution from single fluid phase experiments. We show that these ghost regions have a significantly higher porosity and pore sizes that are an order of magnitude larger than that of unreacted grains. The average thickness of the ghost regions as well as the overall rock dissolution decreases with increasing distance from the injection point. During dissolution micro-porous rock retains much of its original fabric. This suggests that considering the solid part of these ghost regions as macro (bulk) pore space can result in the overestimation of porosity and permeability predicted from segmented X-ray tomographic images, or indeed from reactive transport models that assume a uniform, sharp reaction front at the grain surface.
Scanziani A, Singh K, Bultreys T, et al., 2018, In situ characterization of immiscible three-phase flow at the pore scale for a water-wet carbonate rock, Advances in Water Resources, Vol: 121, Pages: 446-455, ISSN: 0309-1708
X-ray micro-tomography is used to image the pore-scale configurations of fluid in a rock saturated with three phases - brine, oil and gas - mimicking a subsurface reservoir, at high pressure and temperature. We determine pore occupancy during a displacement sequence that involves waterflooding, gas injection and water re-injection. In the water-wet sample considered, brine occupied the smallest pores, gas the biggest, while oil occupied pores of intermediate size and is displaced by both water and gas. Double displacement events have been observed, where gas displaces oil that displaces water or vice versa. The thickness of water and oil layers have been quantified, as have the contact angles between gas and oil, and oil and water. These results are used to explain the nature of trapping in three-phase flow, specifically how oil preferentially traps gas in the presence of water.
Alhammadi AM, AlRatrout A, Bijeljic B, et al., 2018, Pore-scale Imaging and Characterization of Hydrocarbon Reservoir Rock Wettability at Subsurface Conditions Using X-ray Microtomography, Journal of Visualized Experiments, Vol: 140, ISSN: 1940-087X
In situ wettability measurements in hydrocarbon reservoir rocks have only been possible recently. The purpose of this work is to present a protocol to characterize the complex wetting conditions of hydrocarbon reservoir rock using pore-scale three-dimensional X-ray imaging at subsurface conditions. In this work, heterogeneous carbonate reservoir rocks, extracted from a very large producing oil field, have been used to demonstrate the protocol. The rocks are saturated with brine and oil and aged over three weeks at subsurface conditions to replicate the wettability conditions that typically exist in hydrocarbon reservoirs (known as mixed-wettability). After the brine injection, high-resolution three-dimensional images (2 µm/voxel) are acquired and then processed and segmented. To calculate the distribution of the contact angle, which defines the wettability, the following steps are performed. First, fluid-fluid and fluid-rock surfaces are meshed. The surfaces are smoothed to remove voxel artefacts, and in situ contact angles are measured at the three-phase contact line throughout the whole image. The main advantage of this method is its ability to characterize in situ wettability accounting for pore-scale rock properties, such as rock surface roughness, rock chemical composition, and pore size. The in situ wettability is determined rapidly at hundreds of thousands of points. The method is limited by the segmentation accuracy and X-ray image resolution. This protocol could be used to characterize the wettability of other complex rocks saturated with different fluids and at different conditions for a variety of applications. For example, it could help in determining the optimal wettability that could yield an extra oil recovery (i.e., designing brine salinity accordingly to obtain higher oil recovery) and to find the most efficient wetting conditions to trap more CO2 in subsurface formations.
Lutz-Bueno V, Arboleda C, Leu L, et al., 2018, Model-free classification of X-ray scattering signals applied to image segmentation, Journal of Applied Crystallography, Vol: 51, Pages: 1378-1386, ISSN: 0021-8898
In most cases, the analysis of small-angle and wide-angle X-ray scattering(SAXS and WAXS, respectively) requires a theoretical model to describe thesample’s scattering, complicating the interpretation of the scattering resultingfrom complex heterogeneous samples. This is the reason why, in general, theanalysis of a large number of scattering patterns, such as are generated by time-resolved and scanning methods, remains challenging. Here, a model-freeclassification method to separate SAXS/WAXS signals on the basis of theirinflection points is introduced and demonstrated. This article focuses on thesegmentation of scanning SAXS/WAXS maps for which each pixel correspondsto an azimuthally integrated scattering curve. In such a way, the samplecomposition distribution can be segmented through signal classification withoutapplying a model or previous sample knowledge. Dimensionality reduction andclustering algorithms are employed to classify SAXS/WAXS signals according totheir similarity. The number of clusters,i.e.the main sample regions detected bySAXS/WAXS signal similarity, is automatically estimated. From each cluster, amain representative SAXS/WAXS signal is extracted to uncover the spatialdistribution of the mixtures of phases that form the sample. As examples ofapplications, a mudrock sample and two breast tissue lesions are segmented.
Mosser L, Dubrule O, Blunt MJ, 2018, Stochastic Reconstruction of an Oolitic Limestone by Generative Adversarial Networks, TRANSPORT IN POROUS MEDIA, Vol: 125, Pages: 81-103, ISSN: 0169-3913
Lin Q, Bijeljic B, Pini R, et 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.
AlRatrout A, Blunt MJ, Bijeljic B, 2018, Spatial correlation of contact angle and curvature in pore-space images, Water Resources Research, Vol: 54, Pages: 6133-6152, ISSN: 0043-1397
We study the in situ distributions of contact angle and oil/brine interface curvature measured within millimeter-sized rock samples from a producing hydrocarbon carbonate reservoir imaged after waterflooding using X-ray microtomography. We analyze their spatial correlation combining automated methods for measuring contact angles and interfacial curvature (AlRatrout et al., 2017, https://doi.org/10.1016/j.advwatres.2017.07.018), with a recently developed method for pore-network extraction (Raeini et al., 2017, https://doi.org/10.1103/PhysRevE.96.013312). The automated methods allow us to study image volumes of diameter approximately 1.9 mm and 1.2 mm long, obtaining hundreds of thousands of values from a data set with 435 million voxels. We calculate the capillary pressure based on the mode oil/brine interface curvature value and associate this value with a nearby throat in the pore space. We demonstrate the capability of our methods to distinguish different wettability states in the samples studied: water-wet, weakly oil-wet, and mixed-wet. The contact angle and oil/brine interface curvature are spatially correlated over approximately the scale of an average pore. There is a wide distribution of contact angles within a single pore. A range of local oil/brine interface curvature is found with both positive and negative values. There is a correlation between interfacial curvature and contact angle in trapped ganglia, with ganglia in water-wet patches tending to have a positive curvature and oil-wet regions seeing negative curvature. We observed a weak correlation between average contact angle and pore size, with the larger pores tending to be more oil-wet.
AlRatrout A, Blunt MJ, Bijeljic B, 2018, Wettability in complex porous materials, the mixed-wet state, and its relationship to surface roughness, Proceedings of the National Academy of Sciences of the United States of America, Vol: 115, Pages: 8901-8906, ISSN: 0027-8424
A quantitative in situ characterization of the impact of surface roughness on wettability in porous media is currently lacking. We use reservoir condition micrometer-resolution X-ray tomography combined with automated methods for the measurement of contact angle, interfacial curvature, and surface roughness to examine fluid/fluid and fluid/solid interfaces inside a porous material. We study oil and water in the pore space of limestone from a giant producing oilfield, acquiring millions of measurements of curvature and contact angle on three millimeter-sized samples. We identify a distinct wetting state with a broad distribution of contact angle at the submillimeter scale with a mix of water-wet and water-repellent regions. Importantly, this state allows both fluid phases to flow simultaneously over a wide range of saturation. We establish that, in media that are largely water wet, the interfacial curvature does not depend on solid surface roughness, quantified as the local deviation from a plane. However, where there has been a significant wettability alteration, rougher surfaces are associated with lower contact angles and higher interfacial curvature. The variation of both contact angle and interfacial curvature increases with the local degree of roughness. We hypothesize that this mixed wettability may also be seen in biological systems to facilitate the simultaneous flow of water and gases; furthermore, wettability-altering agents could be used in both geological systems and material science to design a mixed-wetting state with optimal process performance.
Shams M, Raeini AQ, Blunt MJ, et al., 2018, A study to investigate viscous coupling effects on the hydraulic conductance of fluid layers in two-phase flow at the pore level, Journal of Colloid and Interface Science, Vol: 522, Pages: 299-310, ISSN: 0021-9797
This paper examines the role of momentum transfer across fluid-fluid interfaces in two-phase flow. A volume-of-fluid finite-volume numerical method is used to solve the Navier-Stokes equations for two-phase flow at the micro-scale. The model is applied to investigate viscous coupling effects as a function of the viscosity ratio, the wetting phase saturation and the wettability, for different fluid configurations in simple pore geometries. It is shown that viscous coupling effects can be significant for certain pore geometries such as oil layers sandwiched between water in the corner of mixed wettability capillaries. A simple parametric model is then presented to estimate general mobility terms as a function of geometric properties and viscosity ratio. Finally, the model is validated by comparison with the mobilities computed using direct numerical simulation.
Akai T, Bijeljic B, Blunt MJ, 2018, Wetting boundary condition for the color-gradient lattice Boltzmann method: Validation with analytical and experimental data, Advances in Water Resources, Vol: 116, Pages: 56-66, ISSN: 0309-1708
In the color gradient lattice Boltzmann model (CG-LBM), a fictitious-density wetting boundary condition has been widely used because of its ease of implementation. However, as we show, this may lead to inaccurate results in some cases. In this paper, a new scheme for the wetting boundary condition is proposed which can handle complicated 3D geometries. The validity of our method for static problems is demonstrated by comparing the simulated results to analytical solutions in 2D and 3D geometries with curved boundaries. Then, capillary rise simulations are performed to study dynamic problems where the three-phase contact line moves. The results are compared to experimental results in the literature (Heshmati and Piri, 2014). If a constant contact angle is assumed, the simulations agree with the analytical solution based on the Lucas–Washburn equation. However, to match the experiments, we need to implement a dynamic contact angle that varies with the flow rate.
Muljadi B, Bijeljic B, Blunt M, et al., 2018, Modelling and upscaling of transport in carbonates during dissolution: validation and calibration with NMR experiments, Journal of Contaminant Hydrology, Vol: 212, Pages: 85-95, ISSN: 0169-7722
We present an experimental and numerical study of transport in carbonates during dissolution and its upscaling from the pore (∼ μm) to core (∼ cm) scale. For the experimental part, we use nuclear magnetic resonance (NMR) to probe molecular displacements (propagators) of an aqueous hydrochloric acid (HCl) solution through a Ketton limestone core. A series of propagator profiles are obtained at a large number of spatial points along the core at multiple time-steps during dissolution. For the numerical part, first, the transport model—a particle-tracking method based on Continuous Time Random Walks (CTRW) by Rhodes et al. (2008)—is validated at the pore scale by matching to the NMR-measured propagators in a beadpack, Bentheimer sandstone, and Portland carbonate Scheven et al. (2005). It was found that the emerging distribution of particle transit times in these samples can be approximated satisfactorily using the power law function ψ(t) ∼ t −1 −β, where 0 < β < 2. Next, the evolution of the propagators during reaction is modelled: at the pore scale, the experimental data is used to calibrate the CTRW parameters; then the shape of the propagators is predicted at later observation times. Finally, a numerical upscaling technique is employed to obtain CTRW parameters for the core. From the NMR-measured propagators, an increasing frequency of displacements in stagnant regions was apparent as the reaction progressed. The present model predicts that non-Fickian behaviour exhibited at the pore scale persists on the centimetre scale.
Bultreys T, Lin Q, Gao Y, et al., 2018, Validation of model predictions of pore-scale fluid distributions during two-phase flow, Physical Review E, Vol: 97, ISSN: 2470-0045
Pore-scale two-phase flow modeling is an important technology to study a rock's relative permeability behavior. To investigate if these models are predictive, the calculated pore-scale fluid distributions which determine the relative permeability need to be validated. In this work, we introduce a methodology to quantitatively compare models to experimental fluid distributions in flow experiments visualized with microcomputed tomography. First, we analyzed five repeated drainage-imbibition experiments on a single sample. In these experiments, the exact fluid distributions were not fully repeatable on a pore-by-pore basis, while the global properties of the fluid distribution were. Then two fractional flow experiments were used to validate a quasistatic pore network model. The model correctly predicted the fluid present in more than 75% of pores and throats in drainage and imbibition. To quantify what this means for the relevant global properties of the fluid distribution, we compare the main flow paths and the connectivity across the different pore sizes in the modeled and experimental fluid distributions. These essential topology characteristics matched well for drainage simulations, but not for imbibition. This suggests that the pore-filling rules in the network model we used need to be improved to make reliable predictions of imbibition. The presented analysis illustrates the potential of our methodology to systematically and robustly test two-phase flow models to aid in model development and calibration.
Alyafei N, Blunt MJ, 2018, Estimation of relative permeability and capillary pressure from mass imbibition experiments, ADVANCES IN WATER RESOURCES, Vol: 115, Pages: 88-94, ISSN: 0309-1708
Lin Q, Andrew M, Thompson W, et al., 2018, Optimization of image quality and acquisition time for lab-based X-ray microtomography using an iterative reconstruction algorithm, Advances in Water Resources, Vol: 115, Pages: 112-124, ISSN: 0309-1708
© 2018 The Authors Non-invasive laboratory-based X-ray microtomography has been widely applied in many industrial and research disciplines. However, the main barrier to the use of laboratory systems compared to a synchrotron beamline is its much longer image acquisition time (hours per scan compared to seconds to minutes at a synchrotron), which results in limited application for dynamic in situ processes. Therefore, the majorit y of existing laboratory X-ray microtomography is limited to static imaging; relatively fast imaging (tens of minutes per scan) can only be achieved by sacrificing imaging quality, e.g. reducing exposure time or number of projections. To alleviate this barrier, we introduce an optimized implementation of a well-known iterative reconstruction algorithm that allows users to reconstruct tomographic images with reasonable image quality, but requires lower X-ray signal counts and fewer projections than conventional methods. Quantitative analysis and comparison between the iterative and the conventional filtered back-projection reconstruction algorithm was performed using a sandstone rock sample with and without liquid phases in the pore space. Overall, by implementing the iterative reconstruction algorithm, the required image acquisition time for samples such as this, with sparse object structure, can be reduced by a factor of up to 4 without measurable loss of sharpness or signal to noise ratio.
Raeini AQ, Bijeljic B, Blunt MJ, 2018, Generalized network modeling of capillary-dominated two-phase flow, Physical Review E, Vol: 97, ISSN: 1539-3755
We present a generalized network model for simulating capillary-dominated two-phase flow through porous media at the pore scale. Three-dimensional images of the pore space are discretized using a generalized network - described in a companion paper [A. Q. Raeini, B. Bijeljic, and M. J. Blunt, Phys. Rev. E 96, 013312 (2017)2470-004510.1103/PhysRevE.96.013312] - which comprises pores that are divided into smaller elements called half-throats and subsequently into corners. Half-throats define the connectivity of the network at the coarsest level, connecting each pore to half-throats of its neighboring pores from their narrower ends, while corners define the connectivity of pore crevices. The corners are discretized at different levels for accurate calculation of entry pressures, fluid volumes, and flow conductivities that are obtained using direct simulation of flow on the underlying image. This paper discusses the two-phase flow model that is used to compute the averaged flow properties of the generalized network, including relative permeability and capillary pressure. We validate the model using direct finite-volume two-phase flow simulations on synthetic geometries, and then present a comparison of the model predictions with a conventional pore-network model and experimental measurements of relative permeability in the literature.
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