Publications
544 results found
Reynolds C, Blunt MJ, Krevor SC, 2018, Multiphase flow characteristics of heterogeneous rocks from CO2 storage reservoirs in the United Kingdom, Water Resources Research, Vol: 54, Pages: 729-745, ISSN: 0043-1397
We have studied the impact of heterogeneity on relative permeability and residual trapping for rock samples from the Bunter sandstone of the UK Southern North Sea, the Ormskirk sandstone of the East Irish Sea, and the Captain sandstone of the UK Northern North Sea. Reservoir condition CO2-brine relative permeability measurements were made while systematically varying the ratio of viscous to capillary flow potential, across a range of flow rates, fractional flow, and during drainage and imbibition displacement. This variation resulted in observations obtained across a range of core-scale capillary number math formula. Capillary pressure heterogeneity was quantitatively inferred from 3-D observations of the fluid saturation distribution in the rocks. For each of the rock samples, a threshold capillary number, math formula, was found, below which centimeter-scale layering resulted in a heterogeneous distribution of the fluid phases and a commensurate impact on flow and trapping. The threshold was found to be dependent on the capillary number alone, irrespective of the displacement path (drainage or imbibition) and average fluid saturation in the rock. The impact of the heterogeneity on the relative permeability varied depending on the characteristics of the heterogeneity in the rock sample, whereas heterogeneity increased residual trapping in all samples above what would be expected from the pore-scale capillary trapping mechanism alone. Models of subsurface CO2 injection should use properties that incorporate the impacts of heterogeneity at the flow regime of interest or risk significant errors in estimates of fluid flow and trapping.
Menke HP, Reynolds CA, Andrew MG, et al., 2018, 4D multi-scale imaging of reactive flow in carbonates: assessing the impact of heterogeneity on dissolution regimes using streamlines at multiple length scales, Chemical Geology, Vol: 481, Pages: 27-37, ISSN: 0009-2541
We have experimentally investigated the impact of heterogeneity on the dissolution of two limestones, characterised by distinct degrees of flow heterogeneity at both the pore and core scales. The two rocks were reacted with reservoir-condition CO 2 -saturated brine at both scales and scanned dynamically during dissolution. First, 1 cm long 4 mm diameter cores were scanned during reactive flow with a 4 μm voxel size between 10 and 71 times using 4D X-ray micro-tomography (μ-CT) over the course of 90 min. Second, 3.8 cm diameter, 8 cm long cores were reacted at the same conditions inside a reservoir-condition flow apparatus and imaged using a medical-grade X-ray computed tomography scanner (XCT). Each sample was imaged ∼13 times over the course of 90 min at a 250 × 250 × 500 μm resolution. These larger cores were then scanned inside a μ-CT at a 27 μm voxel size to assess the alteration pore-space heterogeneity after reaction. Both rock types exhibited channel widening at the mm scale and progressive high porosity pathway dissolution at the cm scale. In the more heterogeneous rock, dissolution was more focussed and progressed along the direction of flow. Additionally, the dissolution pathways contained a distinct microstructure captured with the μ-CT that was not visible at the resolution of the XCT, where the reactive fluid had not completely dissolved the internal pore-structure. This microstructure was further analyzed by performing a direct simulation of the flow field and streamline tracing on the image voxels.We found that at the larger scales the interplay between flow and reaction significantly affects flow in the unreacted regions of the core. When flow is focussed in large reacted channels, this focusing is carried through to the unreacted parts of the rock where flow continues to be confined to preferential pathways after passing the reaction front. This focussing effect is greater with increasing pore space heterogeneity in
Mosser L, Dubrule O, Blunt M, 2018, Stochastic seismic waveform inversion using generative adversarial networks as a geological prior
Setting the seismic inversion problem in a Bayesian framework, we seek to obtain the posterior of acoustic rock properties given a set of seismic observations and a prior distribution of the acoustic properties. We use a generative adversarial network (GAN) based on a deep convolutional neural network to represent the prior distribution of acoustic properties. This prior distribution is derived by applying a neural network to a set of Gaussian latent vectors. Samples of the posterior of these latent vectors are obtained using a Metropolis-sampling method that combines gradients obtained from full waveform inversion with back-propagation through the neural network. We apply the proposed method to a synthetic reservoir-scale dataset of channel bodies.
Scanziani A, Singh K, Bultreys T, et al., 2018, In situ pore-scale visualization of immiscible three-phase flow at high pressure and temperature
© 2018 Society of Petroleum Engineers. All rights reserved. We have used X-ray micro tomography techniques to obtain high quality three-dimensional images of the pore space of a water-wet Ketton carbonate sample and the fluids within it, after the injection of three phases (brine, oil and gas) in a sequence involving oil injection into a fully water-saturated pore space, waterflooding, gas injection and secondary waterflooding. The rock was imaged dry initially, and then again after each injection step, to obtain the saturation of the phases, oil recovery and gas trapping capacity. A maximum ball pore network extraction algorithm was applied on the dry images and used to obtain statistics of pore occupancy. The results are in line with the theories of a uniform water-wet system and with the published outcomes of pore-network simulators: the pore and throat centres of smallest and largest pores are respectively occupied by brine and gas, while the oil resides in the cavities with intermediate size. High resolution images were used to study double displacement and the nature of trapping; the thickness of oil layers were also measured from the images. The results can improve the predicitvity of three-phase flow simulators and improve the efficiency of CO2 storage and utilization.
Nooruddin HA, Blunt MJ, 2018, Large-scale Invasion Percolation with Trapping for Upscaling Capillary-Controlled Darcy-scale Flow, TRANSPORT IN POROUS MEDIA, Vol: 121, Pages: 479-506, ISSN: 0169-3913
Scanziani A, Singh K, Bultreys T, et al., 2018, In situ pore-scale visualization of immiscible three-phase flow at high pressure and temperature
© 2018 Society of Petroleum Engineers. All rights reserved. We have used X-ray micro tomography techniques to obtain high quality three-dimensional images of the pore space of a water-wet Ketton carbonate sample and the fluids within it, after the injection of three phases (brine, oil and gas) in a sequence involving oil injection into a fully water-saturated pore space, waterflooding, gas injection and secondary waterflooding. The rock was imaged dry initially, and then again after each injection step, to obtain the saturation of the phases, oil recovery and gas trapping capacity. A maximum ball pore network extraction algorithm was applied on the dry images and used to obtain statistics of pore occupancy. The results are in line with the theories of a uniform water-wet system and with the published outcomes of pore-network simulators: the pore and throat centres of smallest and largest pores are respectively occupied by brine and gas, while the oil resides in the cavities with intermediate size. High resolution images were used to study double displacement and the nature of trapping; the thickness of oil layers were also measured from the images. The results can improve the predicitvity of three-phase flow simulators and improve the efficiency of CO2 storage and utilization.
Blunt MJ, Dubrule O, Mosser L, 2018, Conditioning of generative adversarial networks for pore and reservoir scale models
Geostatistical modelling of petrophysical properties is a key step in modern integrated oil and gas reservoir studies. Recently, generative adversarial networks (GAN) have been shown to be a successful method for generating unconditional simulations of pore- and reservoir-scale models. This contribution leverages the differentiable nature of neural networks to extend GANS to the conditional simulation of three-dimensional pore- and reservoir-scale models. Based on the previous work of Yeh et al. (2016), we use a content loss to constrain to the conditioning data and a perceptual loss obtained from the evaluation of the GAN discriminator network. The technique is tested on the generation of three-dimensional micro-CT images of a Ketton limestone constrained by two-dimensional cross-sections, and on the simulation of the Maules Creek alluvial aquifer constrained by one-dimensional sections. Our results show that GANs represent a powerful method for sampling conditioned pore and reservoir samples for stochastic reservoir evaluation workflows.
Scanziani A, Singh K, Bultreys T, et al., 2018, In situ pore-scale visualization of immiscible three-phase flow at high pressure and temperature
We have used X-ray micro tomography techniques to obtain high quality three-dimensional images of the pore space of a water-wet Ketton carbonate sample and the fluids within it, after the injection of three phases (brine, oil and gas) in a sequence involving oil injection into a fully water-saturated pore space, waterflooding, gas injection and secondary waterflooding. The rock was imaged dry initially, and then again after each injection step, to obtain the saturation of the phases, oil recovery and gas trapping capacity. A maximum ball pore network extraction algorithm was applied on the dry images and used to obtain statistics of pore occupancy. The results are in line with the theories of a uniform water-wet system and with the published outcomes of pore-network simulators: the pore and throat centres of smallest and largest pores are respectively occupied by brine and gas, while the oil resides in the cavities with intermediate size. High resolution images were used to study double displacement and the nature of trapping; the thickness of oil layers were also measured from the images. The results can improve the predicitvity of three-phase flow simulators and improve the efficiency of CO2 storage and utilization.
Macdonald IA, Blunt MJ, Maitland GC, et al., 2018, Putting CO<inf>2</inf> in its place! A unique research partnership investigating the fundamental principles of subsurface carbon dioxide behaviour and carbonate reservoirs
Carbonate reservoirs hold the majority of CO2 sequestration potential; however, they are also more complicated than sandstone reservoirs in terms of heterogeneity and potential reactivity impact on operations. There are both significant carbonate reservoir CO2 sinks and CO2 point sources around Qatar making carbon capture and storage a potential decarbonisation pathway for the region. The Qatar Carbonates and Carbon Storage Research Centre (QCCSRC) started in 2008 to address the gaps in our current knowledge of both local carbonate reservoir platforms and how CO2 would behave post sequestration. QCCSRC is a research framework agreement over 10 years and valued at $70 million between Qatar Petroleum, Shell, the Qatar Science and Technology Park and Imperial College London bringing together each organisation’s unique capabilities. This novel quadruple helix management structure is responsible for the largest single industrially funded research programme conducted at Imperial College London. Our research has focused on data to create and / or improve predictive models for CO2 storage in carbonate reservoirs. Our three broad thematic areas include: Carbonate Rocks and Reservoir Seals; Rock-fluid interactions; and Fluid-fluid interactions and are supported by five research laboratories. We will review the major scientific outcomes of the programme and the areas where we have identified a greater need for research into our understanding of the underlying science of carbon sequestration. Overall this unique programme is an example of how to approach grand challenges in the energy-carbon dilemma through long-term and multidisciplinary cooperative research.
Blunt MJ, Dubrule O, Mosser L, 2018, Conditioning of generative adversarial networks for pore and reservoir scale models
© 2018 Society of Petroleum Engineers. All rights reserved. Geostatistical modelling of petrophysical properties is a key step in modern integrated oil and gas reservoir studies. Recently, generative adversarial networks (GAN) have been shown to be a successful method for generating unconditional simulations of pore- and reservoir-scale models. This contribution leverages the differentiable nature of neural networks to extend GANS to the conditional simulation of three-dimensional pore- and reservoir-scale models. Based on the previous work of Yeh et al. (2016), we use a content loss to constrain to the conditioning data and a perceptual loss obtained from the evaluation of the GAN discriminator network. The technique is tested on the generation of three-dimensional micro-CT images of a Ketton limestone constrained by two-dimensional cross-sections, and on the simulation of the Maules Creek alluvial aquifer constrained by one-dimensional sections. Our results show that GANs represent a powerful method for sampling conditioned pore and reservoir samples for stochastic reservoir evaluation workflows.
Shams M, Raeini AQ, Blunt MJ, et al., 2017, A numerical model of two-phase flow at the micro-scale using the volume-of-fluid method, Journal of Computational Physics, Vol: 357, Pages: 159-182, ISSN: 0021-9991
This study presents a simple and robust numerical scheme to model two-phase flow in porous media where capillary forces dominate over viscous effects. The volume-of-fluid method is employed to capture the fluid-fluid interface whose dynamics is explicitly described based on a finite volume discretization of the Navier–Stokes equations. Interfacial forces are calculated directly on reconstructed interface elements such that the total curvature is preserved. The computed interfacial forces are explicitly added to the Navier–Stokes equations using a sharp formulation which effectively eliminates spurious currents. The stability and accuracy of the implemented scheme is validated on several two- and three-dimensional test cases, which indicate the capability of the method to model two-phase flow processes at the micro-scale. In particular we show how the co-current flow of two viscous fluids leads to greatly enhanced flow conductance for the wetting phase in corners of the pore space, compared to a case where the non-wetting phase is an inviscid gas.
Gao Y, Lin Q, Bijeljic B, et al., 2017, X-ray Microtomography of Intermittency in Multiphase Flow at Steady State Using a Differential Imaging Method, Water Resources Research, Vol: 53, Pages: 10274-10292, ISSN: 0043-1397
We imaged the steady state flow of brine and decane in Bentheimer sandstone. We devised an experimental method based on differential imaging to examine how flow rate impacts impact the pore-scale distribution of fluids during coinjection. This allows us to elucidate flow regimes (connected, or breakup of the nonwetting phase path ways) for a range of fractional flows at two capillary numbers, Ca, namely 3.0 × 10 −7 and 7.5 × 10 −6 . At the lower Ca, for a fixed fractional flow, the two phases appear to flow in connected unchanging subnetworks of the pore space, consistent with conventional theory. At the higher Ca, we observed that a significant fraction of the pore space contained sometimes oil and sometimes brine during the 1 h scan: this intermittent occupancy, which was interpreted as regions of the pore space that contained both fluid phases for some time, is necessary to explain the flow and dynamic connectivity of the oil phase; pathways of always oil-filled portions of the void space did not span the core. This phase was segmented from the differential image between the 30 wt % KI brine image and the scans taken at each fractional flow. Using the grey scale histogram distribution of the raw images, the oil proportion in the intermittent phase was calculated. The pressure drops at each fractional flow at low and high flow rates were measured by high-precision differential pressure sensors. The relative permeabilities and fractional flow obtained by our experiment at the mm-scale compare well with data from the literature on cm-scale samples.
Al-Khulaifi Y, Lin Q, Blunt MJ, et al., 2017, Reservoir-condition pore-scale imaging of dolomite reaction with supercritical CO<inf>2</inf>acidified brine: Effect of pore-structure on reaction rate using velocity distribution analysis, International Journal of Greenhouse Gas Control, Vol: 68, Pages: 99-111, ISSN: 1750-5836
To investigate the impact of rock heterogeneity and flowrate on reaction rates and dissolution dynamics, four millimetre-scale Silurian dolomite samples were pre-screened based on their physical heterogeneity, defined by the simulated velocity distributions characterising each flow field. Two pairs of cores with similar heterogeneity were flooded with supercritical carbon-dioxide (scCO 2 ) saturated brine under reservoir conditions, 50 °C and 10 MPa, at a high (0.5 ml/min) and low (0.1 ml/min) flowrate. Changes to the pore structure brought about by dissolution were captured in situ using X-ray microtomography (micro-CT) imaging. Mass balance from effluent analysis sh owed a good agreement with calculations from imaging. Image calculated reaction rates (r eff ) were 5-38 times lower than the corresponding batch reaction rate under the same conditions of temperature and pressure but without mass transfer limitations. For both high (Péclet number = 2600-1200) and low (Péclet number = 420-300) flow rates, an impact of the initial rock heterogeneity was observed on both reaction rates and permeability-porosity relationships.
Alhammadi ASY, AlRatrout A, bijeljic B, et al., 2017, In situ Wettability Measurement in a Carbonate Reservoir Rock at High Temperature and Pressure, SPE Abu Dhabi International Petroleum Exhibition & Conference, Publisher: Society of Petroleum Engineers
More than a trillion barrels of oil may be extracted from carbonate reservoirs in the Middle East. Oil recovery is known to be controlled by wettability (distribution of contact angles) that determines the pore-scale fluid configuration. However, these contact angles have not hitherto been measured in situ at reservoir conditions for reservoir rock that is saturated with formation brine and crude oil. We use high resolution X-ray imaging of a sample from a producing oil field to demonstrate that contact angles over a wide range are seen both above and below 90°. More than a million points of contact angle were measured after three pore volumes of formation brine flooding. The injected brine invades the center of the pores as a non-wetting phase leaving oil trapped in small pores and corners in connected layers.Pores that were filled with initial formation brine remained water-wet. On the other hand, surfaces that were in direct contact with crude oil during aging were altered to oil-wet. However, water-wet surfaces were also measured in pores that were filled with crude oil which suggests that water layers in small pores, crevices, and within rock surface roughness, which might be connected to brine in micro-porosity, could prevent the contact between surface active polar compounds in the crude oil and the rock surfaces preventing strong wettability change. The reservoir rock became mixed-wet with a mean contact angle of 106° ± 20° obtained from 1.36 million in situ contact angle values measured using an automated algorithm (AlRatrout et al., 2017) applied on segmented three-dimensional X-ray image. The three-dimensional images were acquired using a high resolution X-ray micro-tomography scanner. The wetting condition resulted in a large volume of oil (50.6%) being trapped with a distinctive morphology as rough sheet-like layers.
Mosser L, Dubrule O, Blunt MJ, 2017, Reconstruction of three-dimensional porous media using generative adversarial neural networks, Physical Review E, Vol: 96, Pages: 1-17, ISSN: 1539-3755
To evaluate the variability of multiphase flow properties of porous media at the pore scale, it is necessary toacquire a number of representative samples of the void-solid structure. While modern x-ray computer tomographyhas made it possible to extract three-dimensional images of the pore space, assessment of the variability in theinherent material properties is often experimentally not feasible. We present a method to reconstruct thesolid-void structure of porous media by applying a generative neural network that allows an implicit descriptionof the probability distribution represented by three-dimensional image data sets. We show, by using an adversariallearning approach for neural networks, that this method of unsupervised learning is able to generate representativesamples of porous media that honor their statistics. We successfully compare measures of pore morphology, suchas the Euler characteristic, two-point statistics, and directional single-phase permeability of synthetic realizationswith the calculated properties of a bead pack, Berea sandstone, and Ketton limestone. Results show that generativeadversarial networks can be used to reconstruct high-resolution three-dimensional images of porous media atdifferent scales that are representative of the morphology of the images used to train the neural network.The fully convolutional nature of the trained neural network allows the generation of large samples whilemaintaining computational efficiency. Compared to classical stochastic methods of image reconstruction, theimplicit representation of the learned data distribution can be stored and reused to generate multiple realizationsof the pore structure very rapidly
Alhammadi AM, AlRatrout A, Singh K, et al., 2017, In situ characterization of mixed-wettability in a reservoir rock at subsurface conditions., Scientific Reports, Vol: 7, ISSN: 2045-2322
We used X-ray micro-tomography to image the in situ wettability, the distribution of contact angles, at the pore scale in calcite cores from a producing hydrocarbon reservoir at subsurface conditions. The contact angle was measured at hundreds of thousands of points for three samples after twenty pore volumes of brine flooding.We found a wide range of contact angles with values both above and below 90°. The hypothesized cause of wettability alteration by an adsorbed organic layer on surfaces contacted by crude oil after primary drainage was observed with Scanning Electron Microscopy (SEM) and identified using Energy Dispersive X-ray (EDX) analysis. However, not all oil-filled pores were altered towards oil-wet conditions, which suggests that water in surface roughness, or in adjacent micro-porosity, can protect the surface from a strong wettability alteration. The lowest oil recovery was observed for the most oil-wet sample, where the oil remained connected in thin sheet-like layers in the narrower regions of the pore space. The highest recovery was seen for the sample with an average contact angle close to 90°, with an intermediate recovery in a more water-wet system, where the oil was trapped in ganglia in the larger regions of the pore space.
Lin Q, Bijeljic B, Rieke H, et al., 2017, Visualization and quantification of capillary drainage in the pore space of laminated sandstone by a porous plate method using differential imaging X-ray microtomography, WATER RESOURCES RESEARCH, Vol: 53, Pages: 7457-7468, ISSN: 0043-1397
The experimental determination of capillary pressure drainage curves at the pore scale is ofvital importance for the mapping of reservoir fluid distribution. To fully characterize capillary drainage in acomplex pore space, we design a differential imaging-based porous plate (DIPP) method using X-ray micro-tomography. For an exemplar mm-scale laminated sandstone microcore with a porous plate, we quantifythe displacement from resolvable macropores and subresolution micropores. Nitrogen (N2) was injected asthe nonwetting phase at a constant pressure while the porous plate prevented its escape. The measuredporosity and capillary pressure at the imaged saturations agree well with helium measurements and experi-ments on larger core samples, while providing a pore-scale explanation of the fluid distribution. Weobserved that the majority of the brine was displaced by N2in macropores at low capillary pressures, fol-lowed by a further brine displacement in micropores when capillary pressure increases. Furthermore, wewere able to discern that brine predominantly remained within the subresolution micropores, such asregions of fine lamination. The capillary pressure curve for pressures ranging from 0 to 1151 kPa is providedfrom the image analysis compares well with the conventional porous plate method for a cm-scale core butwas conducted over a period of 10 days rather than up to few months with the conventional porous platemethod. Overall, we demonstrate the capability of our method to provide quantitative information on two-phase saturation in heterogeneous core samples for a wide range of capillary pressures even at scalessmaller than the micro-CT resolution
Reynolds CA, Menke H, Andrew M, et al., 2017, Dynamic fluid connectivity during steady-state multiphase flow in a sandstone, Proceedings of the National Academy of Sciences of the United States of America, Vol: 114, Pages: 8187-8192, ISSN: 0027-8424
The current conceptual picture of steady-state multiphase Darcy flow in porous media is that the fluid phases organize into separate flow pathways with stable interfaces. Here we demonstrate a previously unobserved type of steady-state flow behavior, which we term “dynamic connectivity,” using fast pore-scale X-ray imaging. We image the flow of N2 and brine through a permeable sandstone at subsurface reservoir conditions, and low capillary numbers, and at constant fluid saturation. At any instant, the network of pores filled with the nonwetting phase is not necessarily connected. Flow occurs along pathways that periodically reconnect, like cars controlled by traffic lights. This behavior is consistent with an energy balance, where some of the energy of the injected fluids is sporadically converted to create new interfaces.
AlRatrout A, Raeini AQ, Bijeljic B, et al., 2017, Automatic measurement of contact angle in pore-space images, Advances in Water Resources, Vol: 109, Pages: 158-169, ISSN: 0309-1708
A new approach is presented to measure the in-situ contact angle (θ) between immiscible fluids, applied to segmented pore-scale X-ray images. We first identify and mesh the fluid/fluid and fluid/solid interfaces. A Gaussian smoothing is applied to this mesh to eliminate artifacts associated with the voxelized nature of the image, while preserving large-scale features of the rock surface. Then, for the fluid/fluid interface we apply an additional smoothing and adjustment of the mesh to impose a constant curvature. We then track the three-phase contact line, and the two vectors that have a direction perpendicular to both surfaces: the contact angle is found from the dot product of these vectors where they meet at the contact line. This calculation can be applied at every point on the mesh at the contact line. We automatically generate contact angle values representing each invaded pore-element in the image with high accuracy.To validate the approach, we first study synthetic three-dimensional images of a spherical droplet of oil residing on a tilted flat solid surface surrounded by brine and show that our results are accurate to within 3° if the sphere diameter is 2 or more voxels. We then apply this method to oil/brine systems imaged at ambient temperature and reservoir pressure (10MPa) using X-ray microtomography (Singh et al., 2016). We analyse an image volume of diameter approximately 4.6 mm and 10.7 mm long, obtaining hundreds of thousands of values from a dataset with around 700 million voxels. We show that in a system of altered wettability, contact angles both less than and greater than 90° can be observed.This work provides a rapid method to provide an accurate characterization of pore-scale wettability, which is important for the design and assessment of hydrocarbon recovery and carbon dioxide storage.
Raeini AQ, Bijeljic B, Blunt MJ, 2017, Generalized network modeling: Network extraction as a coarse-scale discretization of the void space of porous media, PHYSICAL REVIEW E, Vol: 96, ISSN: 2470-0045
A generalized network extraction workflow is developed for parameterizing three-dimensional (3D) images of porous media. The aim of this workflow is to reduce the uncertainties in conventional network modeling predictions introduced due to the oversimplification of complex pore geometries encountered in natural porous media. The generalized network serves as a coarse discretization of the surface generated from a medial-axis transformation of the 3D image. This discretization divides the void space into individual pores and then subdivides each pore into sub-elements called half-throat connections. Each half-throat connection is further segmented into corners by analyzing the medial axis curves of its axial plane. The parameters approximating each corner—corner angle, volume, and conductivity—are extracted at different discretization levels, corresponding to different wetting layer thickness and local capillary pressures during multiphase flow simulations. Conductivities are calculated using direct single-phase flow simulation so that the network can reproduce the single-phase flow permeability of the underlying image exactly. We first validate the algorithm by using it to discretize synthetic angular pore geometries and show that the network model reproduces the corner angles accurately. We then extract network models from micro-CT images of porous rocks and show that the network extraction preserves macroscopic properties, the permeability and formation factor, and the statistics of the micro-CT images.
Singh K, Menke H, Andrew M, et al., 2017, Dynamics of snap-off and pore-filling events during two-phase fluid flow in permeable media, SCIENTIFIC REPORTS, Vol: 7, ISSN: 2045-2322
Understanding the pore-scale dynamics of two-phase fluid flow in permeable media is important in many processes such as water infiltration in soils, oil recovery, and geo-sequestration of CO2. The two most important processes that compete during the displacement of a non-wetting fluid by a wetting fluid are pore-filling or piston-like displacement and snap-off; this latter process can lead to trapping of the non-wetting phase. We present a three-dimensional dynamic visualization study using fast synchrotron X-ray micro-tomography to provide new insights into these processes by conducting a time-resolved pore-by-pore analysis of the local curvature and capillary pressure. We show that the time-scales of interface movement and brine layer swelling leading to snap-off are several minutes, orders of magnitude slower than observed for Haines jumps in drainage. The local capillary pressure increases rapidly after snap-off as the trapped phase finds a position that is a new local energy minimum. However, the pressure change is less dramatic than that observed during drainage. We also show that the brine-oil interface jumps from pore-to-pore during imbibition at an approximately constant local capillary pressure, with an event size of the order of an average pore size, again much smaller than the large bursts seen during drainage.
Saif T, Lin Q, Butcher AR, et al., 2017, Multi-scale multi-dimensional microstructure imaging of oil shale pyrolysis using X-ray micro-tomography, automated ultra-high resolution SEM, MAPS Mineralogy and FIB-SEM, Applied Energy, Vol: 202, Pages: 628-647, ISSN: 0306-2619
The complexity of unconventional rock systems is expressed both in the compositional variance of the microstructure and the extensive heterogeneity of the pore space. Visualizing and quantifying the microstructure of oil shale before and after pyrolysis permits a more accurate determination of petrophysical properties which are important in modeling hydrocarbon production potential. We characterize the microstructural heterogeneity of oil shale using X-ray micro-tomography (µCT), automated ultra-high resolution scanning electron microscopy (SEM), MAPS Mineralogy (Modular Automated Processing System) and Focused Ion Beam Scanning Electron Microscopy (FIB-SEM). The organic-rich Eocene Green River (Mahogany zone) oil shale is characterized using a multi-scale multi-dimensional workflow both before and after pyrolysis. Observations in 2-D and 3-D and across nm-µm-mm length scales demonstrate both heterogeneity and anisotropy at every scale. Image acquisition and analysis using µCT and SEM reveal a microstructure of alternating kerogen-rich laminations interbedded with layers of fine-grained inorganic minerals. MAPS Mineralogy combined with ultrafast measurements reveal mineralogic textures dominated by dolomite, calcite, K-feldspar, quartz, pyrite and illitic clays along with their spatial distribution, augmenting conventional mineral analysis. From high resolution Backscattered electron (BSE) images, intra-organic, inter-organic-mineral, intra- and inter-mineral pores are observed with varying sizes and geometries. By using FIB milling and SEM imaging sequentially and repetitively, 3-D data sets were reconstructed. By setting 3-D gradient and marker-based watershed transforms, the organic matter, minerals and pore phases (including pore-back artifacts) were segmented and visualized and the pore-size distribution was computed. Following pyrolysis, fractures from the mm-to-µm scales were observed with preferential propagation along the kerogen-ric
Lin Q, Bijeljic B, Rieke H, et al., 2017, Differential imaging of porous plate capillary drainage in laminated sandstone rock using X-ray micro-tomography, 79th EAGE Conference and Exhibition 2017 - Workshops, Publisher: European Association of Geoscientists & Engineers
The experimental determination of capillary pressure drainage curves at the pore scale is of vital importance for the mapping of reservoir fluid distribution. To fully characterize capillary drainage in a complex pore space, we design a differential imaging-based porous plate (DIPP) method using X-ray microtomography. For an exemplar mm-scale laminated sandstone microcore with a porous plate, we quantify the displacement from resolvable macropores and subresolution micropores. Nitrogen (N2) was injected as the nonwetting phase at a constant pressure while the porous plate prevented its escape. The measured porosity and capillary pressure at the imaged saturations agree well with helium measurements and experiments on larger core samples, while providing a pore-scale explanation of the fluid distribution. We observed that the majority of the brine was displaced by N2 in macropores at low capillary pressures, followed by a further brine displacement in micropores when capillary pressure increases. Furthermore, we were able to discern that brine predominantly remained within the subresolution micropores, such as regions of fine lamination. The capillary pressure curve for pressures ranging from 0 to 1151 kPa is provided from the image analysis compares well with the conventional porous plate method for a cm-scale core but was conducted over a period of 10 days rather than up to few months with the conventional porous plate method. Overall, we demonstrate the capability of our method to provide quantitative information on two-phase saturation in heterogeneous core samples for a wide range of capillary pressures even at scales smaller than the micro-CT resolution.
Foley AY, Nooruddin HA, Blunt MJ, 2017, The impact of capillary backpressure on spontaneous counter-current imbibition in porous media, ADVANCES IN WATER RESOURCES, Vol: 107, Pages: 405-420, ISSN: 0309-1708
We investigate the impact of capillary backpressure on spontaneous counter-current imbibition. For such displacements in strongly water-wet systems, the non-wetting phase is forced out through the inlet boundary as the wetting phase imbibes into the rock, creating a finite capillary backpressure. Under the assumption that capillary backpressure depends on the water saturation applied at the inlet boundary of the porous medium, its impact is determined using the continuum modelling approach by varying the imposed inlet saturation in the analytical solution.We present analytical solutions for the one-dimensional incompressible horizontal displacement of a non-wetting phase by a wetting phase in a porous medium. There exists an inlet saturation value above which any change in capillary backpressure has a negligible impact on the solutions. Above this threshold value, imbibition rates and front positions are largely invariant. A method for identifying this inlet saturation is proposed using an analytical procedure and we explore how varying multiphase flow properties affects the analytical solutions and this threshold saturation. We show the value of this analytical approach through the analysis of previously published experimental data.
Saif T, Lin Q, Bijeljic B, et al., 2017, Microstructural imaging and characterization of oil shale before and after pyrolysis, FUEL, Vol: 197, Pages: 562-574, ISSN: 0016-2361
The microstructural evaluation of oil shale is challenging which demands the use of several complementary methods. In particular, an improved insight into the pore network structure and connectivity before, during, and after oil shale pyrolysis is critical to understanding hydrocarbon flow behavior and enhancing recovery. In this experimental study, bulk analyses are combined with traditional and advanced imaging methods to comprehensively characterize the internal microstructure and chemical composition of the world’s richest oil shale deposit, the Green River Formation (Mahogany Zone). Image analysis in two dimensions (2-D) using optical and scanning electron microscopy (SEM), and in three dimensions (3-D) using X-ray microtomography (µCT) reveals a complex and variable fine-grained microstructure dominated by organic-rich parallel laminations of the order of 10 µm thick which are tightly bound in a highly calcareous and heterogeneous mineral matrix. We also report the results of a detailed µCT study of the Mahogany oil shale with increasing pyrolysis temperature (300–500 °C) at 12 µm and 2 µm voxel sizes. The physical transformation of the internal microstructure and evolution of pore space during the thermal conversion of kerogen in oil shale to produce hydrocarbon products was characterized. The 3-D volumes of pyrolyzed oil shale were reconstructed and image processed to visualize and quantify the volume and connectivity of the pore space. The results show a significant increase in anisotropic porosity associated with pyrolysis between 400 and 500 °C with the formation of micro-scale connected pore channels developing principally along the kerogen-rich lamellar structures. Given the complexity and heterogeneity of oil shale, we also characterize the representative size at which porosity remains constant. Our results provide a direct observation of pore and microfracture development during oil shale pyrolysis and
Al-Khulaifi Y, Lin Q, Blunt MJ, et al., 2017, Reaction Rates in Chemically Heterogeneous Rock: Coupled Impact of Structure and Flow Properties Studied by X-ray Microtomography, ENVIRONMENTAL SCIENCE & TECHNOLOGY, Vol: 51, Pages: 4108-4116, ISSN: 0013-936X
We study dissolution in a chemically heterogeneous medium consisting of two minerals with contrasting initial structure and transport properties. We perform a reactive transport experiment using CO2-saturated brine at reservoir conditions in a millimeter-scale composite core composed of Silurian dolomite and Ketton limestone (calcite) arranged in series. We repeatedly image the composite core using X-ray microtomography (XMT) and collect effluent to assess the individual mineral dissolution. The mineral dissolution from image analysis was comparable to that measured from effluent analysis using inductively coupled plasma mass spectrometry (ICP-MS). We find that the ratio of the effective reaction rate of calcite to that of dolomite decreases with time, indicating the influence of dynamic transport effects originating from changes in pore structure coupled with differences in intrinsic reaction rates. Moreover, evolving flow and transport heterogeneity in the initially heterogeneous dolomite is a key determinant in producing a two-stage dissolution in the calcite. The first stage is characterized by a uniform dissolution of the pore space, while the second stage follows a single-channel growth regime. This implies that spatial memory effects in the medium with a heterogeneous flow characteristic (dolomite) can change the dissolution patterns in the medium with a homogeneous flow characteristic (calcite).
Menke HP, Andrew MG, Blunt MJ, et al., 2017, Dynamic pore-scale reservoir-condition imaging of reaction in carbonates using synchrotron fast tomography, Journal of Visualized Experiments, Vol: 120, ISSN: 1940-087X
Synchrotron fast tomography was used to dynamically image dissolution of limestone in the presence of CO2-saturated brine at reservoir conditions. 100 scans were taken at a 6.1 µm resolution over a period of 2 hours. Underground storage permanence is a major concern for carbon capture and storage. Pumping CO2 into carbonate reservoirs has the potential to dissolve geologic seals and allow CO2 to escape. However, the dissolution processes at reservoir conditions are poorly understood. Thus, time-resolved experiments are needed to observe and predict the nature and rate of dissolution at the pore scale. Synchrotron fast tomography is a method of taking high-resolution time-resolved images of complex pore structures much more quickly than traditional µ-CT . The Diamond Lightsource Pink Beam was used to dynamically image dissolution of limestone in the presence of CO2-saturated brine at reservoir conditions. 100 scans were taken at a 6.1 µm resolution over a period of 2 hours. The images were segmented and the porosity and permeability were measured using image analysis and network extraction. Porosity increased uniformly along the length of the sample; however, the rate of increase of both porosity and permeability slowed at later times.
Menke HP, Bijeljic B, Blunt M, 2017, Dynamic reservoir-condition microtomography of reactive transport in complex carbonates: effect of initial pore structure and initial brine pH, Geochimica et Cosmochimica Acta, Vol: 204, Pages: 267-285, ISSN: 1872-9533
We study the impact of brine acidity and initial pore structure on the dynamics of fluid/solid reaction at high Péclet numbers and low Damköhler numbers. A laboratory μ-CT scanner was used to image the dissolution of Ketton, Estaillades, and Portland limestones in the presence of CO2-acidified brine at reservoir conditions (10 MPa and 50°C) at two injected acid strengths for a period of 4 hours. Each sample was scanned between 6 and 10 times at ∼4 μm resolution and multiple effluent samples were extracted. The images were used as inputs into flow simulations, and analysed for dynamic changes in porosity, permeability, and reaction rate. Additionally, the effluent samples were used to verify the image-measured porosity changes.We find that initial brine acidity and pore structure determine the type of dissolution. Dissolution is either uniform where the porosity increases evenly both spatially and temporally, or occurs as channelling where the porosity increase is concentrated in preferential flow paths. Ketton, which has a relatively homogeneous pore structure, dissolved uniformly at pH = 3.6 but showed more channelized flow at pH = 3.1. In Estaillades and Portland, increasingly complex carbonates, channelized flow was observed at both acidities with the channel forming faster at lower pH. It was found that the effluent pH, which is higher than that injected, is a reasonably good indicator of effective reaction rate during uniform dissolution, but a poor indicator during channelling. The overall effective reaction rate was up to 18 times lower than the batch reaction rate measured on a flat surface at the effluent pH, with the lowest reaction rates in the samples with the most channelized flow, confirming that transport limitations are the dominant mechanism in determining reaction dynamics at the fluid/solid boundary.
Scanziani A, Singh K, Blunt MJ, et al., 2017, Automatic method for estimation of in situ effective contact angle from X-ray micro tomography images of two-phase flow in porous media, Journal of Colloid and Interface Science, Vol: 496, Pages: 51-59, ISSN: 1095-7103
Multiphase flow in porous media is strongly influenced by the wettability of the system, which affects the arrangement of the interfaces of different phases residing in the pores. We present a method for estimating the effective contact angle, which quantifies the wettability and controls the local capillary pressure within the complex pore space of natural rock samples, based on the physical constraint of constant curvature of the interface between two fluids. This algorithm is able to extract a large number of measurements from a single rock core, resulting in a characteristic distribution of effective in situ contact angle for the system, that is modelled as a truncated Gaussian probability density distribution. The method is first validated on synthetic images, where the exact angle is known analytically; then the results obtained from measurements within the pore space of rock samples imaged at a resolution of a few microns are compared to direct manual assessment. Finally the method is applied to X-ray micro computed tomography (micro-CT) scans of two Ketton cores after waterflooding, that display water-wet and mixed-wet behaviour. The resulting distribution of in situ contact angles is characterized in terms of a mixture of truncated Gaussian densities.
Bartels W-B, Rucker M, Berg S, et al., 2017, Fast X-Ray Micro-CT Study of the Impact of Brine Salinity on the Pore-Scale Fluid Distribution During Waterflooding, PETROPHYSICS, Vol: 58, Pages: 36-47, ISSN: 1529-9074
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