Imperial College London

ProfessorMartinBlunt

Faculty of EngineeringDepartment of Earth Science & Engineering

Chair in Petroleum Engineering
 
 
 
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Contact

 

+44 (0)20 7594 6500m.blunt Website

 
 
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Location

 

2.38ARoyal School of MinesSouth Kensington Campus

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Summary

 

Publications

Publication Type
Year
to

461 results found

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

Mosser L, Dubrule O, Blunt M, 2019, Deep stochastic inversion

© 81st EAGE Conference and Exhibition 2019. All rights reserved. Numerous modelling 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 deep learning 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. Then 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 then 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.

Conference paper

Mosser L, Dubrule O, Blunt M, 2019, Deep stochastic inversion

© 81st EAGE Conference and Exhibition 2019. All rights reserved. Numerous modelling 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 deep learning 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. Then 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 then 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.

Conference paper

Mosser L, Dubrule O, Blunt M, 2019, Deep stochastic inversion

© 81st EAGE Conference and Exhibition 2019. All rights reserved. Numerous modelling 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 deep learning 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. Then 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 then 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.

Conference paper

Oliveira TDS, Blunt MJ, Bijeljic B, 2019, Modelling of multispecies reactive transport on pore-space images, Advances in Water Resources, Vol: 127, Pages: 192-208, ISSN: 0309-1708

We present a new model, named poreReact, to simulate multispecies reactive transport on pore space images. We solve the Navier–Stokes equations and the advection-diffusion equation for concentration on an unstructured grid using the finite volume method implemented in OpenFOAM. We couple it with the chemical model Reaktoro, which we use to calculate the chemical equilibrium of homogeneous reactions in each grid cell, considered as a completely mixed batch reactor. We validate the model against analytical solutions and experimental data, and investigate, for a range of Péclet numbers, the interplay between transport and reaction for multispecies reactive transport in a 3D bead pack where two streams of reactants at different pH are injected in parallel. We analyse the distribution of species and the rates of formation and consumption in the pore space and find that, despite the relative homogeneity of the bead pack and symmetry in injection conditions, the concentration fields of the products can be asymmetric because of the interplay between transport and chemical equilibrium. For different Péclet numbers, we calculate relative yields (the ratio between the observed change in concentration and the change that would be obtained if the reactants were completely mixed). We observe that lower Péclet numbers give rise to higher relative yields because of increased transverse mixing by diffusion. However, higher absolute yields are obtained at higher injection velocities because of the larger amount of matter available for reaction in a given time. Reaction is more favoured in the faster-flowing regions of the pore space. However, this effect is more marked for species for which advection is the dominant mechanism of transport to reactive sites, as opposed to diffusion-mediated reactions where the full velocity distribution is sampled before reaction occurs.

Journal article

Al-Khulaifi Y, Lin Q, Blunt MJ, Bijeljic Bet al., 2019, Pore-scale dissolution by CO₂ saturated brine in a multimineral carbonate at reservoir conditions: impact of physical and chemical heterogeneity, Water Resources Research, Vol: 55, Pages: 3171-3193, ISSN: 0043-1397

We study the impact of physical and chemical heterogeneity on reaction rates in multimineral porous media. We selected two pairs of carbonate samples of different physical heterogeneity in accordance with their initial computed velocity distributions and then injected CO 2 saturated brine at reservoir conditions at two flow rates. We periodically imaged the samples using X-ray microtomography. The mineralogical composition was similar (a ratio of dolomite to calcite of 8:1), but the intrinsic reaction rates and mineral spatial distribution were profoundly different. Visualizations of velocity fields and reacted mineral distributions revealed that a dominant flow channel formed in all cases. The more physically homogeneous samples had a narrower velocity distribution and more preexisting fast channels, which promoted dominant channel formation in their proximity. In contrast, the heterogeneous samples exhibit a broader distribution of velocities and fewer fast channels, which accentuated nonuniform calcite distribution and favored calcite dissolution away from the initially fast pathways. We quantify the impact of physical and chemical heterogeneity by computing the proximity of reacted minerals to the fast flow pathways. The average reaction rates were an order of magnitude lower than the intrinsic ones due to mass transfer limitations. The effective reaction rate of calcite decreased by an order of magnitude, in both fast channels and slow regions. After channel formation calcite was shielded by dolomite whose effective rate in slow regions could even increase. Overall, the preferential channeling effect, as opposed to uniform dissolution, was promoted by a higher degree of physical and/or chemical heterogeneity.

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

Rücker M, Bartels WB, Singh K, Brussee N, Coorn A, van der Linde HA, Bonnin A, Ott H, Hassanizadeh SM, Blunt MJ, Mahani H, Georgiadis A, Berg Set al., 2019, The Effect of Mixed Wettability on Pore-Scale Flow Regimes Based on a Flooding Experiment in Ketton Limestone, Geophysical Research Letters, Vol: 46, Pages: 3225-3234, ISSN: 0094-8276

© 2019. The Authors. Darcy-scale multiphase flow in geological formations is significantly influenced by the wettability of the fluid-solid system. So far it has not been understood how wettability impacts the pore-scale flow regimes within rocks, which were in most cases regarded as an alteration from the base case of strongly water-wet conditions by adjustment of contact angles. In this study, we directly image the pore-scale flow regime in a carbonate altered to a mixed-wet condition by aging with crude oil to represent the natural configuration in an oil reservoir with fast synchrotron-based X-ray computed tomography. We find that the pore-scale flow regime is dominated by ganglion dynamics in which the pore space is intermittently filled with oil and brine. The frequency and size of these fluctuations are greater than in water-wet rock such that their impact on the overall flow and relative permeability cannot be neglected in modeling approaches.

Journal article

Singh K, Muljadi B, Raeini AQ, Jost C, Vandeginste V, Blunt MJ, Theraulaz G, Degond Pet al., 2019, The architectural design of smart ventilation and drainage systems in termite nests, Science Advances, Vol: 5, ISSN: 2375-2548

Termite nests have been widely studied as effective examples for ventilation and thermoregulation;however, the mechanisms by which the nest properties are controlled by the micro-structure of the outer walls remain unclear. Here, we combine multi-scale X-ray imaging with three-dimensional flow field simulations to investigate the impact of the architectural design of nest walls on CO2and heat transport as well as on water drainage. We show that termites construct an outer wall that contains both small and percolating large pores at the micro-scale. The network of larger micro-scale pores in the outer wall provides a permeability that is 1-2 orders of magnitude greater than that of the smaller pores, andaCO2diffusivitythat is a factor of up to eight times larger. The largerpores and resultant high porosity also reduce the solid mass required for nest construction by ~11-14%. This is energetically favorable and reduces the overall weight of the nest, thus lowering the risk of collapse. In addition, the pore network offers enhanced thermal insulation to the inner parts of the nest and allows quick drainage ofrainwater thereby restoring the ventilation and providing structural stability to the wet nest.

Journal article

Akai T, Alhammadi AM, Blunt MJ, Bijeljic Bet al., 2019, Modeling oil recovery in mixed-wet rocks: Pore-scale comparison between experiment and simulation, Transport in Porous Media, Vol: 127, Pages: 393-414, ISSN: 0169-3913

To examine the need to incorporate in situ wettability measurements in direct numerical simulations, we compare waterflooding experiments in a mixed-wet carbonate from a producing reservoir and results of direct multiphase numerical simulations using the color-gradient lattice Boltzmann method. We study the experiments of Alhammadi et al. (Sci Rep 7(1):10753, 2017. https://doi.org/10.1038/s41598-017-10992-w) where the pore-scale distribution of remaining oil was imaged using micro-CT scanning. In the experiment, in situ contact angles were measured using an automated algorithm (AlRatrout et al. in Adv Water Resour 109:158–169, 2017. https://doi.org/10.1016/j.advwatres.2017.07.018), which indicated a mixed-wet state with spatially non-uniform angles. In our simulations, the pore structure was obtained from segmented images of the sample used in the experiment. Furthermore, in situ measured angles were also incorporated into our simulations using our previously developed wetting boundary condition (Akai et al. in Adv Water Resour 116(March):56–66, 2018. https://doi.org/10.1016/j.advwatres.2018.03.014). We designed six simulations with different contact angle assignments based on experimentally measured values. Both a constant contact angle based on the average value of the measured values and non-uniform contact angles informed by the measured values gave a good agreement for fluid pore occupancy between the simulation and the experiment. However, the constant contact angle assignment predicted 54% higher water effective permeability after waterflooding than that estimated for the experimental result, whereas the non-uniform contact angle assignment gave less than 1% relative error. This means that to correctly predict fluid conductivity in mixed-wet rocks, a spatially heterogeneous wettability state needs to be taken into account. The novelty of this work is to provide a direct pore-scale comparison between experiments and simulations employing experiment

Journal article

Saif T, Lin Q, Gao Y, Al-Khulaifi Y, Marone F, Hollis D, Blunt MJ, Bijeljic Bet 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.

Journal article

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

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.

Conference paper

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.

Conference paper

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.

Conference paper

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.

Conference paper

Lin Q, Alhammadi AM, Gao Y, Bijeljic B, Blunt MJet al., 2019, Iscal for complete rock characterization: Using pore-scale imaging to determine relative permeability and capillary pressure

© 2019, Society of Petroleum Engineers 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

Conference paper

Mosser L, Dubrule O, Blunt MJ, 2019, Deep stochastic inversion

© EAGE 2019. 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.

Conference paper

Leu L, Bertier P, Georgiadis A, Busch A, Diaz A, Klaver J, Schmatz J, Lutz-Bueno V, Ihli J, Ott H, Blunt Met al., 2019, SAXS and WAXS microscopy applied to mudrocks: A new method for systematic multiscale studies of porosity, pore orientation and mineralogy

© 2019 European Association of Geoscientists and Engineers, EAGE. All Rights Reserved. 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.

Conference paper

Akai T, Alhammadi AM, Blunt MJ, Bijeljic Bet al., 2019, Direct multiphase numerical simulation on mixed-wet reservoir carbonates

© Copyright 2018, Society of Petroleum Engineers. 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.

Conference paper

Scanziani A, Alhammadi A, Bijeljic B, Blunt MJet al., 2019, Three-phase flow visualization and characterization for a mixed-wet carbonate rock

© Copyright 2018, Society of Petroleum Engineers. 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.

Conference paper

Singh K, Menke H, Andrew M, Rau C, Bijeljic B, Blunt MJet 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.

Journal article

Singh K, Anabaraonye BU, Blunt MJ, Crawshaw Jet 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.

Journal article

Scanziani A, Singh K, Bultreys T, Bijeljic B, Blunt MJet 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.

Journal article

Alhammadi AM, AlRatrout A, Bijeljic B, Blunt MJet 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.

Journal article

Lutz-Bueno V, Arboleda C, Leu L, Blunt MJ, Busch A, Georgiadis A, Bertier P, Schmatz J, Varga Z, Villanueva-Perez P, Wang Z, Lebugle M, David C, Stampanoni M, Diaz A, Guizar-Sicairos M, Menzel Aet 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.

Journal article

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

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

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.

Journal article

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, 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.

Journal article

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