Publications
544 results found
Schmid KS, Alyafei N, Geiger S, et al., 2016, Analytical Solutions for Spontaneous Imbibition: Fractional-Flow Theory and Experimental Analysis, SPE JOURNAL, Vol: 21, Pages: 2308-2316, ISSN: 1086-055X
Xie C, Raeini AQ, Wang Y, et al., 2016, An improved pore-network model including viscous coupling effects using direct simulation by the lattice Boltzmann method, ADVANCES IN WATER RESOURCES, Vol: 100, Pages: 26-34, ISSN: 0309-1708
Leu L, Georgiadis A, Blunt MJ, et al., 2016, Multiscale description of shale pore systems by scanning SAXS and WAXS microscopy, Energy & Fuels, Vol: 30, Pages: 10282-10297, ISSN: 1520-5029
The pore space of shales and mudrocks ranges from molecular dimensions to micrometers in length scale. This leads to great variation in spatial characteristics across many orders of magnitude, which poses a challenge for the determination of a representative microscopic pore network for such systems. Standard characterization techniques generally provide volume-averaged properties while high-resolution imaging techniques do not assess a representative range of pore sizes because of limitations in the spatial resolution over the field of view. Due to this complexity, open questions remain regarding the role of the pore network in retention and transport processes, which in turn control oil and gas production. Volume-averaged but spatially resolved information is obtained for pores of size from 2 to 150 nm by applying scanning small- and wide-angle X-ray scattering (SAXS and WAXS) microscopy. Scattering patterns are collected in a scanning microscopy mode, such that microvoxels are sampled sequentially, over a total of 2 × 2 mm2 raster area on specifically prepared thin sections with a thickness of 10–30 μm. Spatially resolved variations of porosity, pore-size distribution, orientation, as well as mineralogy are derived simultaneously. Aiming at a full characterization of the shale pore network, the measurements and subsequent matrix porosity analysis are integrated in a multiscale imaging workflow involving FIB-SEM, SEM, and μ-CT analysis.
Berkowitz B, Blunt M, Scher H, 2016, Preface: Special Issue in Honor of Harvey Scher's 80th Birthday, TRANSPORT IN POROUS MEDIA, Vol: 115, Pages: 209-214, ISSN: 0169-3913
Lin Q, Al-Khulaifi Y, Blunt M, et al., 2016, Quantification of sub-resolution porosity in carbonate rocks by applying high-salinity contrast brine using X-ray microtomography differential imaging, Advances in Water Resources, Vol: 96, Pages: 306-322, ISSN: 0309-1708
Characterisation of the pore space in carbonate reservoirs and aquifers is of utmost importance in a number of applications such as enhanced oil recovery, geological carbon storage and contaminant transport. We present a new experimental methodology that uses high-salinity contrast brine and differential imaging acquired by X-ray tomography to non-invasively obtain three-dimensional spatially resolved information on porosity and connectivity of two rock samples, Portland and Estaillades limestones, including sub-resolution micro-porosity. We demonstrate that by injecting 30 wt% KI brine solution, a sufficiently high phase contrast can be achieved allowing accurate three-phase segmentation based on differential imaging. This results in spatially resolved maps of the solid grain phase, sub-resolution micro-pores within the grains, and macro-pores. The total porosity values from the three-phase segmentation for two carbonate rock samples are shown to be in good agreement with Helium porosity measurements. Furthermore, our flow-based method allows for an accurate estimate of pore connectivity and a distribution of porosity within the sub-resolution pores.
Nooruddin HA, Blunt MJ, 2016, Analytical and numerical investigations of spontaneous imbibition in porous media, Water Resources Research, Vol: 52, Pages: 7284-7310, ISSN: 1944-7973
We present semianalytical solutions for cocurrent displacements with some degree of countercurrent flow. The solution assumes a one-dimensional horizontal displacement of two immiscible incompressible fluids with arbitrary viscosities and saturation-dependent relative permeability and capillary pressures. We address the impact of the system length on the degree of countercurrent flow when there is no pressure drop in the nonwetting phase across the system, assuming negligible capillary back pressure at the inlet boundary of the system. It is shown that in such displacements, the fractional flow can be used to determine a critical water saturation, from which regions of both cocurrent and countercurrent flow are identified. This critical saturation changes with time as the saturation front moves into the porous medium. Furthermore, the saturation profile in the approach presented here is not necessarily a function of distance divided by the square root of time. We also present approximate solutions using a perturbative approach, which is valid for a wide range of flow conditions. This approach requires less computational power and is much easier to implement than the implicit integral solutions used in previous work. Finally, a comprehensive comparison between analytical and numerical solutions is presented. Numerical computations are performed using traditional finite-difference formulations and convergence analysis shows a generally slow convergence rate for water imbibition rates and saturation profiles. This suggests that most coarsely gridded simulations give a poor estimate of imbibition rates, while demonstrating the value of these analytical solutions as benchmarks for numerical studies, complementing Buckley-Leverett analysis.
Al Nahari Alhashmi Z, Blunt MJ, Bijeljic B, 2016, The impact of pore structure heterogeneity, transport, and reaction conditions on fluid/fluid reaction rate studied on images of pore space, Transport in Porous Media, Vol: 115, Pages: 215-237, ISSN: 1573-1634
We perform direct numerical simulation using a pore-scale fluid–fluid reactive transport model (Alhashmi et al. in J Contam Hydrol 179:171–181, 2015. doi:10.1016/j.jconhyd.2015.06.004) to investigate the impact of pore structure heterogeneity on the effective reaction rate in different porous media. We simulate flow, transport, and reaction in three pore-scale images: a beadpack, Bentheimer sandstone, and Doddington sandstone for a range of transport and reaction conditions. We compute the reaction rate, velocity distributions, and dispersion coefficient comparing them with the results for non-reactive transport. The rate of reaction is a subtle combination of the amount of mixing and spreading that cannot be predicted from the non-reactive dispersion coefficient. We demonstrate how the flow field heterogeneity affects the effective reaction rate. Dependent on the intrinsic flow field heterogeneity characteristic and the flow rate, reaction may: (a) occur throughout the zones where both resident and injected particles exist (for low Péclet number and a homogeneous flow field), (b) preferentially occur at the trailing edge of the plume (for high Péclet number and a homogeneous flow field), or (c) be disfavored in slow-moving zones (for high Péclet number and a heterogeneous flow field).
Pereira Nunes JP, Bijeljic B, Blunt MJ, 2016, Pore-space structure and average dissolution rates: A simulation study, Water Resources Research, Vol: 52, Pages: 7198-7212, ISSN: 0043-1397
We study the influence of the pore-space geometry on sample-averaged dissolution rates in millimeter-scale carbonate samples undergoing reaction-controlled mineral dissolution upon the injection of a CO2 -saturated brine. The representation of the pore space is obtained directly from micro-CT images with a resolution of a few microns. Simulations are performed with a particle tracking approach on images of three porous rocks of increasing pore-space complexity: a bead pack, a Ketton oolite, and an Estaillades limestone. Reactive transport is simulated with a hybrid approach that combines a Lagrangian method for transport and reaction with the Eulerian flow field obtained by solving the incompressible Navier-Stokes equations directly on the voxels of three-dimensional images. Particle advection is performed with a semianalytical streamline method and diffusion is simulated via a random walk. Mineral dissolution is defined in terms of the particle flux through the pore-solid interface, which can be related analytically to the batch (intrinsic) reaction rate. The impact of the flow heterogeneity on reactive transport is illustrated in a series of simulations performed at different flow rates. The average dissolution rates depend on both the heterogeneity of the sample and on the flow rate. The most heterogeneous rock may exhibit a decrease of up to two orders of magnitude in the sample-averaged reaction rates in comparison with the batch rate. Furthermore, we provide new insights for the dissolution regime that would be traditionally characterized as uniform. In most cases, at the pore-scale, dissolution preferentially enlarges fast-flow channels which greatly restricts the effective surface available for reaction.
Alyafei N, Al-Menhali A, Blunt MJ, 2016, Experimental and Analytical Investigation of Spontaneous Imbibition in Water-Wet Carbonates, TRANSPORT IN POROUS MEDIA, Vol: 115, Pages: 189-207, ISSN: 0169-3913
Al-menhali A, Menke H, Blunt MJ, et al., 2016, Pore Scale Observations of Trapped CO2 in Mixed-Wet Carbonate Rock: Applications to Storage in Oil Fields, Environmental Science & Technology, Vol: 50, Pages: 10282-10290, ISSN: 0013-936X
Geologic CO2 storage has been identified as a key to avoiding dangerous climate change. Storage in oil reservoirs dominates the portfolio of existing projects due to favorable economics. However, in an earlier related work (Al-Menhali and Krevor Environ. Sci. Technol. 2016, 50, 2727−2734), it was identified that an important trapping mechanism, residual trapping, is weakened in rocks with a mixed wetting state typical of oil reservoirs. We investigated the physical basis of this weakened trapping using pore scale observations of supercritical CO2 in mixed-wet carbonates. The wetting alteration induced by oil provided CO2-wet surfaces that served as conduits to flow. In situ measurements of contact angles showed that CO2 varied from nonwetting to wetting throughout the pore space, with contact angles ranging 25° < θ < 127°; in contrast, an inert gas, N2, was nonwetting with a smaller range of contact angle 24° < θ < 68°. Observations of trapped ganglia morphology showed that this wettability allowed CO2 to create large, connected, ganglia by inhabiting small pores in mixed-wet rocks. The connected ganglia persisted after three pore volumes of brine injection, facilitating the desaturation that leads to decreased trapping relative to water-wet systems.
Bajwa AI, Blunt MJ, 2016, Early-Time 1D Analysis of Shale-Oil and -Gas Flow, SPE JOURNAL, Vol: 21, Pages: 1254-1262, ISSN: 1086-055X
Saif T, Lin Q, Singh K, et al., 2016, Dynamic imaging of oil shale pyrolysis using synchrotron X-ray microtomography, Geophysical Research Letter, Vol: 43, Pages: 6799-6807, ISSN: 0094-8276
The structure and connectivity of the pore space during the pyrolysis of oil shales determines hydrocarbon flow behavior and ultimate recovery. We image the time evolution of the pore and microfracture networks during oil shale pyrolysis using synchrotron X-ray microtomography. Immature Green River (Mahogany Zone) shale samples were thermally matured under vacuum conditions at temperatures up to 500°C while being periodically imaged with a 2μmvoxel size. The structural transformation of both organic-rich and organic-lean layers within the shale was quantified. The images reveal a dramatic change in porosity accompanying pyrolysis between 390 and 400°C with the formation of micron-scale heterogeneous pores. With a further increase in temperature, the pores steadily expand resulting in connected microfracture networks that predominantly develop along the kerogen-rich laminations.
Nunes JPP, Bijeljic B, Blunt MJ, 2016, Simulating carbonate dissolution with digital rock physics, Third EAGE/SBGf Workshop 2016 Quantitative Seismic Interpretation of Lacustrine Carbonates, Pages: 56-59
The increase in CO2-injection activities for Capture Carbon and Sequestration (CCS) and Enhanced Oil Recovery (EOR) is pushing the industry and the academia to explore the implications of rock-fluid interactions in full-scale development projects of carbonate reservoirs. Some of the questions are: Do reactions occur at rates that make a substantial impact on petrophysical properties? Are they relevant for CCS and/or oil recovery? How do they impact monitoring strategies? Carbonate reservoirs are notoriously difficult to characterize. Their abrupt facies variations give rise to drastic changes in the petrophysical and mechanical properties of the reservoir. Such heterogeneity, when further associated with variations in rock mineralogy due to diagenetic processes, results in a challenging scenario to model from the pore- to the field-scale. Micro-CT imaging is one of the most promising technologies to characterize porous rocks. The understanding of reactive and non-reactive transport at the pore scale is being pushed forward by recent developments in both imaging capability - 3D images with resolution of a few microns - and in modelling techniques - flow simulations in giga-cell models. We present a streamline-based pore-scale simulation method to predict the evolution of petrophysical properties of carbonate cores subjected to CO2 injection at reservoir conditions.
Singh K, Bijeljic B, Blunt MJ, 2016, Imaging of oil layers, curvature and contact angle in a mixed-wet and a water-wet carbonate rock, Water Resources Research, Vol: 52, Pages: 1716-1728, ISSN: 1944-7973
Menke HP, Andrew MG, Blunt MJ, et al., 2016, Reservoir condition imaging of reactive transport in heterogeneous carbonates using fast synchrotron tomography - effect of initial pore structure and flow conditions, Chemical Geology, Vol: 428, Pages: 15-26, ISSN: 1872-6836
We investigate the impact of initial pore structure and velocity field heterogeneity on the dynamics of fluid/solid reaction at high Péclet numbers (fast flow) and low Damköhler number (relatively slow reaction rates). The Diamond Lightsource Pink Beam was used to image dissolution of Estaillades and Portland limestones in the presence of CO2-saturated brine at reservoir conditions (10 MPa and 50 °C representing ~1 km aquifer depth) at two flow rates for a period of 2 h. Each sample was scanned between 51 and 94 times at 4.76-μm resolution and the dynamic changes in porosity, permeability, and reaction rate were examined using image analysis and flow modelling. We find that the porosity can either increase uniformly through time along the length of the samples, or may exhibit a spatially and temporally varying increase that is attributed to channel formation, a process that is distinct from wormholing, depending on initial pore structure and flow conditions. The dissolution regime was structure-dependent: Estaillades with a higher porosity showed more uniform dissolution, while the lower porosity Portland experienced channel formation. The effective reaction rates were up to two orders of magnitude lower than those measured on a flat substrate with no transport limitations, indicating that the transport of reactant and product is severely hampered away from fast flow channels.
Alyafei N, Blunt MJ, 2016, The effect of wettability on capillary trapping in carbonates, Advances in Water Resources, Vol: 90, Pages: 36-50, ISSN: 1872-9657
We use an organic acid (cyclohexanepentanoic acid) to alter the wettability of three carbonates: Estaillades, Ketton and Portland limestones, and observe the relationship between the initial oil saturation and the residual saturation. We take cores containing oil and a specified initial water saturation and waterflood until 10 pore volumes have been injected. We record the remaining oil saturation as a function of the amount of water injected. In the water-wet case, with no wettability alteration, we observe, as expected, a monotonic increase in the remaining oil saturation with initial saturation. However, when the wettability is altered, we observe an increase, then a decrease, and finally an increase in the trapping curve for Estaillades limestone with a small, but continued, decrease in the remaining saturation as more water is injected. This behavior is indicative of mixed-wet or intermediate-wet conditions, as there is no spontaneous imbibition of oil and water. In contrast, Ketton did not show indications of a significant wettability alteration with a similar observed trapping profile to that observed in the water-wet case. Portland limestone also showed a monotonic increasing trend in remaining saturation with initial saturation but with a higher recovery, and less trapping, than the water-wet case. Again, this is intermediate-wet behavior with no spontaneous imbibition of either oil or water, and slow production of oil after water breakthrough. Finally, we repeat the same experiments but instead we age the three carbonates with a high asphaltenic content and high viscosity crude oil at 70 °C mimicking reservoir conditions. The results show a monotonic increase in residual saturation as a function of initial saturation but with higher recovery than the water-wet cases for Estaillades and Portland, with again no indication of wettability alteration for Ketton. We discuss the results in terms of pore-scale recovery process and contact angle hysteresis. In
Pereira Nunes JP, Blunt MJ, Bijeljic B, 2016, Pore-scale simulation of carbonate dissolution in micro-CT images, Journal of Geophysical Research: Solid Earth, Vol: 121, Pages: 558-576, ISSN: 2169-9356
We present a particle-based method to simulate carbonate dissolution at the pore scale directly on the voxels of three-dimensional micro-CT images. The flow field is computed on the images by solving the incompressible Navier-Stokes equations. Rock-fluid interaction is modeled using a three-step approach: solute advection, diffusion, and reaction. Advection is simulated with a semianalytical pore-scale streamline tracing algorithm, diffusion by random walk is superimposed, while the reaction rate is defined by the flux of particles through the pore-solid interface. We derive a relationship between the local particle flux and the independently measured batch calcite dissolution rate. We validate our method against a dynamic imaging experiment where a Ketton oolite is imaged during CO2-saturated brine injection at reservoir conditions. The image-calculated increases in porosity and permeability are predicted accurately, and the spatial distribution of the dissolution front is correctly replicated. The experiments and simulations are performed at a high flow rate, in the uniform dissolution regime – Pe ≫ 1 and PeDa ≪ 1—thus extending the reaction throughout the sample. Transport is advection dominated, and dissolution is limited to regions with significant inflow of solute. We show that the sample-averaged reaction rate is 1 order of magnitude lower than that measured in batch reactors. This decrease is the result of restrictions imposed on the flux of solute to the solid surface by the heterogeneous flow field, at the millimeter scale.
Spagnuolo M, Callegaro C, Masserano F, et al., 2016, Low salinity waterflooding: From single well chemical tracer test interpretation to sector model forecast scenarios
We study Enhanced Oil Recovery (EOR) through Low Salinity (LS) waterflooding in a brown oil field. LS waterflooding is an emerging EOR technique in which water with reduced salinity is injected into a reservoir to improve oil recovery, as compared with conventional waterflooding, in which High Salinity (HS) brine or seawater are commonly used. The efficiency of this technique can be quantified at the well-scale by a Single Well Chemical Tracer Test (SWCTT), which is an in-situ method for measuring the Remaining Oil Saturation (ROS) after flooding the near-wellbore region with a displacing agent. Two SWCTTs were executed on a sandstone North African field. The tests were realized in sequence with seawater and LS water to evaluate the EOR potential at the well-scale. Here, we propose the interpretation of these two SWCTTs. They were modeled through numerical simulations because of the presence of several non-idealities in the complex scenario considered. A recently-developed tracer simulator was employed to solve the reactive transport problem. This was used as a fast post-processing tool coupled with a conventional reservoir simulator. Model parameters were estimated within an inverse modeling framework, on the basis of an assisted history matching procedure that exploits the Metropolis Hastings Algorithm (MHA). Results were scaled up on a sector model of the field, and forecast scenarios that consider a field-scale implementation of this technique were defined. The well-scale displacement efficiency gain associated with LS water, as compared with seawater, was evaluated. It was quantified as a ROS reduction of 8 saturation unit (s.u.), with a P10-P90 range of 3-15 s.u. Reservoir-scale simulations suggest that the associated ultimate oil recovery of the EOR pilot may be increased by 2% with LS water, with a P10-P90 range of 0.7-4.3%. Overall, the LS EOR potential for a selected field was quantified through a robust and original workflow, based on SWCTT interpretation
Spagnuolo M, Callegaro C, Masserano F, et al., 2016, Low salinity waterflooding: From single well chemical tracer test interpretation to sector model forecast scenarios
We study Enhanced Oil Recovery (EOR) through Low Salinity (LS) waterflooding in a brown oil field. LS waterflooding is an emerging EOR technique in which water with reduced salinity is injected into a reservoir to improve oil recovery, as compared with conventional waterflooding, in which High Salinity (HS) brine or seawater are commonly used. The efficiency of this technique can be quantified at the well-scale by a Single Well Chemical Tracer Test (SWCTT), which is an in-situ method for measuring the Remaining Oil Saturation (ROS) after flooding the near-wellbore region with a displacing agent. Two SWCTTs were executed on a sandstone North African field. The tests were realized in sequence with seawater and LS water to evaluate the EOR potential at the well-scale. Here, we propose the interpretation of these two SWCTTs. They were modeled through numerical simulations because of the presence of several non-idealities in the complex scenario considered. A recently-developed tracer simulator was employed to solve the reactive transport problem. This was used as a fast post-processing tool coupled with a conventional reservoir simulator. Model parameters were estimated within an inverse modeling framework, on the basis of an assisted history matching procedure that exploits the Metropolis Hastings Algorithm (MHA). Results were scaled up on a sector model of the field, and forecast scenarios that consider a field-scale implementation of this technique were defined. The well-scale displacement efficiency gain associated with LS water, as compared with seawater, was evaluated. It was quantified as a ROS reduction of 8 saturation unit (s.u.), with a P10-P90 range of 3-15 s.u. Reservoir-scale simulations suggest that the associated ultimate oil recovery of the EOR pilot may be increased by 2% with LS water, with a P10-P90 range of 0.7-4.3%. Overall, the LS EOR potential for a selected field was quantified through a robust and original workflow, based on SWCTT interpretation
Leu LD, Georgiadis A, Blunt MJ, et al., 2016, Bridging pore and macroscopic scale - Scanning SAXS-WAXS microscopy applied to shales, Pages: 18-21
The determination of fabric and pore structure of shales remains a challenging task which is mainly due to the wide range of pore sizes (and shapes) ranging from molecular dimensions to microns. High resolution imaging techniques fail to provide information over representative regions of interest, while more conventional characterization techniques may only assess volume averaged properties of the pore systems. Thus, open questions remain regarding the effects of the multi-scale pore network of shales in the retention and transport of hydrocarbons during unconventional production processes. We apply scanning small- and wide-angle X-ray scattering (SAXS and WAXS) microscopy to obtain averaged but detailed information from the micro- and meso-pore structures of shales. By combining SAXS/WAXS with raster-scanning microscopy, we obtain local scattering information from 1-100 nm-size pores in micrometer-size volumes over a large (2 x 2) mm2 scanning area. We derive porosity, pore size distribution and orientation, as well as mineralogy of specially prepared thin section samples, covering length scale ranges of nm to submicrons and from microns to millimeters, with a gap that can potentially be closed The method further enables the linking of porosity to shale matrix components, which is integrated in a multi-scale imaging workflow involving μCT, and SEM/EDX analysis, aimed at allowing for the full pore network characterization of shales.
Abushaikha AS, Blunt MJ, Gosselin OR, et al., 2015, Interface control volume finite element method for modelling multi-phase fluid flow in highly heterogeneous and fractured reservoirs, JOURNAL OF COMPUTATIONAL PHYSICS, Vol: 298, Pages: 41-61, ISSN: 0021-9991
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- Citations: 32
Porta GM, Bijeljic B, Blunt MJ, et al., 2015, Continuum-scale characterization of solute transport based on pore-scale velocity distributions, Geophysical Research Letters, Vol: 42, Pages: 7537-7545, ISSN: 1944-8007
We present a methodology to characterize a continuum-scale model of transport in porous media on the basis of pore-scale distributions of velocities computed in three-dimensional pore-space images. The methodology is tested against pore-scale simulations of flow and transport for a bead pack and a sandstone sample. We employ a double-continuum approach to describe transport in mobile and immobile regions. Model parameters are characterized through inputs resulting from the micron-scale reconstruction of the pore space geometry and the related velocity field. We employ the outputs of pore-scale analysis to (i) quantify the proportion of mobile and immobile fluid regions and (ii) assign the velocity distribution in an effective representation of the medium internal structure. Our results (1) show that this simple conceptual model reproduces the spatial profiles of solute concentration rendered by pore-scale simulation without resorting to model calibration and (2) highlight the critical role of pore-scale velocities in the characterization of the model parameters.
Pereira Nunes JP, Bijeljic B, Blunt MJ, 2015, Time-of-Flight Distributions and Breakthrough Curves in Heterogeneous Porous Media Using a Pore-Scale Streamline Tracing Algorithm, TRANSPORT IN POROUS MEDIA, Vol: 109, Pages: 317-336, ISSN: 0169-3913
Alyafei N, Raeini AQ, Paluszny Rodriguez A, et al., 2015, A Sensitivity Study of the Effect of Image Resolution on Predicted Petrophysical Properties, TRANSPORT IN POROUS MEDIA, ISSN: 0169-3913
Raeini AQ, Bijeljic B, Blunt MJ, 2015, Modelling capillary trapping using finite-volume simulation of two-phase flow directly on micro-CT images, ADVANCES IN WATER RESOURCES, Vol: 83, Pages: 102-110, ISSN: 0309-1708
Andrew M, Menke H, Blunt MJ, et al., 2015, The imaging of dynamic multiphase fluid flow using synchrotron-based x-ray microtomography at reservoir conditions, Transport in Porous Media, Vol: 110, Pages: 1-24, ISSN: 1573-1634
Fast synchrotron-based X-ray microtomography was used to image the injection ofsuper-critical CO2 under subsurface conditions into a brine-saturated carbonate sample at thepore-scale with a voxel size of 3.64µm and a temporal resolution of 45 s. Capillary pressurewas measured from the images by finding the curvature of terminal menisci of both connectedand disconnected CO2 clusters. We provide an analysis of three individual dynamic drainageevents at elevated temperatures and pressures on the tens of seconds timescale, showing nonlocalinterface recession due to capillary pressure change, and both local and distal (non-local)snap-off. The measured capillary pressure change is not sufficient to explain snap-off in thissystem, as the disconnected CO2 has a much lower capillary pressure than the connectedCO2 both before and after the event. Disconnected regions instead preserve extremely lowdynamic capillary pressures generated during the event. Snap-off due to these dynamic effectsis not only controlled by the pore topography and throat radius, but also by the local fluidarrangement. Whereas disconnected fluid configurations produced by local snap-off wererapidly reconnected with the connected CO2 region, distal snap-off produced much morelong-lasting fluid configurations, showing that dynamic forces can have a persistent impacton the pattern and sequence of drainage events.
Andrew MG, Menke HP, Blunt MJ, et al., 2015, The Imaging of Dynamic Multiphase Fluid Flow Using Synchrotron-Based X-ray Microtomography at Reservoir Conditions, Transport in Porous Media, Vol: 110, Pages: 1-24, ISSN: 1573-1634
Alhashmi Z, Blunt MJ, Bijeljic B, 2015, Predictions of Dynamic Changes in Reaction Rates as aConsequence of Incomplete Mixing Using Pore-scale Reactive TransportModeling on Images of Porous Media, Journal of Contaminant Hydrology, Vol: 179, Pages: 171-181, ISSN: 1873-6009
We present a pore scale model capable of simulating fluid/fluid reactive transport on images of porous media from first principles. We use a streamline-based particle tracking method for simulating flow and transport, while for reaction to occur, both reactants must be within a diffusive distance of each other during a time-step. We assign a probability of reaction (Pr), as a function of the reaction rate constant (kr) and the diffusion length. Firstly, we validate our model for reaction against analytical solutions for the bimolecular reaction (A + B → C) in a free fluid. Then, we simulate transport and reaction in a beadpack to validate the model through predicting the fluid/fluid reaction experimental results provided by Gramling et al. (2002). Our model accurately predicts the experimental data, as it takes into account the degree of incomplete mixing present at the sub-pore (image voxel) level, in contrast to advection–dispersion–reaction equation (ADRE) model that over-predicts pore scale mixing. Finally, we show how our model can predict dynamic changes in the reaction rate accurately accounting for the local geometry, topology and flow field at the pore scale. We demonstrate the substantial difference between the predicted early-time reaction rate in comparison to the ADRE model.
Muljadi B, Blunt MJ, Raeini A, et al., 2015, The impact of porous media heterogeneity on non-Darcy flow behaviour from pore-scale simulation, Advances in Water Resources, Vol: 95, Pages: 329-340, ISSN: 1872-9657
The effect of pore-scale heterogeneity on non-Darcy flow behaviour is investigated by means of direct flow simulations on 3-D images of a beadpack, Bentheimer sandstone and Estaillades carbonate. The critical Reynolds number indicating the cessation of the creeping Darcy flow regime in Estaillades carbonate is two orders of magnitude smaller than in Bentheimer sandstone, and is three orders of magnitude smaller than in the beadpack. It is inferred from the examination of flow field features that the emergence of steady eddies in pore space of Estaillades at elevated fluid velocities accounts for the early transition away from the Darcy flow regime. The non-Darcy coefficient β, the onset of non-Darcy flow, and the Darcy permeability for all samples are obtained and compared to available experimental data demonstrating the predictive capability of our approach. X-ray imaging along with direct pore-scale simulation of flow provides a viable alternative to experiments and empirical correlations for predicting non-Darcy flow parameters such as the β factor, and the onset of non-Darcy flow.
Jackson MD, Percival JR, Mostaghiml P, et al., 2015, Reservoir modeling for flow simulation by use of surfaces, adaptive unstructured meshes, and an overlapping-control-volume finite-element method, SPE Reservoir Evaluation and Engineering, Vol: 18, Pages: 115-132, ISSN: 1094-6470
We present new approaches to reservoir modeling and flow simulation that dispose of the pillar-grid concept that has persisted since reservoir simulation began. This results in significant improvements to the representation of multiscale geologic heterogeneity and the prediction of flow through that heterogeneity. The research builds on more than 20 years of development of innovative numerical methods in geophysical fluid mechanics, refined and modified to deal with the unique challenges associated with reservoir simulation.Geologic heterogeneities, whether structural, stratigraphic, sedimentologic, or diagenetic in origin, are represented as discrete volumes bounded by surfaces, without reference to a predefined grid. Petrophysical properties are uniform within the geologically defined rock volumes, rather than within grid cells. The resulting model is discretized for flow simulation by use of an unstructured, tetrahedral mesh that honors the architecture of the surfaces. This approach allows heterogeneity over multiple length-scales to be explicitly captured by use of fewer cells than conventional corner-point or unstructured grids.Multiphase flow is simulated by use of a novel mixed finite-element formulation centered on a new family of tetrahedral element types, PN(DG)–PN+1, which has a discontinuous Nth-order polynomial representation for velocity and a continuous (order N +1) representation for pressure. This method exactly represents Darcy-force balances on unstructured meshes and thus accurately calculates pressure, velocity, and saturation fields throughout the domain. Computational costs are reduced through dynamic adaptive-mesh optimization and efficient parallelization. Within each rock volume, the mesh coarsens and refines to capture key flow processes during a simulation, and also preserves the surface-based representation of geologic heterogeneity. Computational effort is thus focused on regions of the model where it is most required.After valid
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