Immiscible viscous fingering in porous media continues to attract significant interest. The concept has been originally derived for Hele-Shaw geometries and then applied to (multiphase) immiscible displacement in Darcy scale porous media. In the Hele-Shaw geometry, the finger wavelength arises from a competition between the viscous instability and a capillary restoring force associated with the Laplace pressure of the curved interfaces between displacing and displaced phases. The well-known derivation by Saffmann and Taylor predicts that the dominant wavelength scales with the square root of interfacial tension and permeability over viscosity and velocity. However, for Darcy scale viscous fingering a linear scaling with interfacial tension is observed, consistent with the less well-known long-wavelength instability by King and Dunayevsky and Yortsos and Hickernell. In their linear stability analysis "mixing" within the capillary dispersion zone is assumed to moderate the mobility contrast at the displacement front, which controls the finger wavelength. By using fine-gridded Darcy scale numerical simulations, we find that the capillary dispersion zone has approximately the same width as the finger wavelength and both scale linearly with interfacial tension. This confirms that capillary dispersion is indeed the mechanism controlling finger wavelength, leading to a linear and not a square-root scaling. By using approximations for the width of the capillary dispersion zone, a very much simplified semi-analytical derivation provides a simple closed-form prediction of the finger wavelength. It naturally gives the correct scaling with interfacial tension, permeability, and injection velocity, and it predicts the finger wavelength within a factor of 2.3 or better for CO2 underground storage scenarios in the context of carbon capture and storage. Quantitative mismatches mainly originate from uncertainty in the choice of shock-front vs end point reference saturation to evaluate mobility contrast and capillary dispersion.

Geomethanation, the in situ conversion of hydrogen and carbon dioxide into methane through the microbial activity of methanogens within geological formations, remains a promising technology for simultaneous carbon dioxide utilization, hydrogen storage, and natural gas production. Despite interest in this process, uncertainties persist regarding the efficiency of the conversion process and its competitiveness for subsurface space, particularly given the increasing demand for hydrogen storage and carbon sequestration. Detailed knowledge of relevant reservoirs, combined with laboratory testing, is needed to evaluate the potential subsurface environments for hydrogen methanation. Several factors, such as substrate availability and supply and presence of essential nutrients in brine, govern microbial growth and conversion efficiency. developed a coupled experimental-numerical approach that combines a novel high-resolution microfluidic platform with direct numerical simulations to resolve mass transfer and methane production kinetics at the pore scale. The workflow includes micromodel colonization, anaerobic introduction of substrates, and gas analysis via chromatography measurements. A microfluidic reactor setup was used to investigate biomass distribution and gas dynamics and to calibrate the numerically determined results, which may have significant implications for gas conversion and recovery. (1) During substrate gas injection, microbial aggregation shifted from colony-dominated lifestyle to a planktonic lifestyle. (2) The observed colony disintegration and cell migration toward gas-liquid interfaces may support substrate uptake and conversion efficiency. The experiments yielded a methane evolution rate, peaking at similar to 0.35 mmol/Lh. (3) Dimensionless analysis revealed distinct transport regimes within the pore network, ranging from molecular diffusion to advective mixing. These findings demonstrate that a balance among microbial activity, interfacial mass transfer, and advective nutrient supply governs the geomethanation process in unsaturated flow environments.

The carbon capture and storage (CCS) potential in Austria remains to be elucidated as the country plans to lift its CO2 storage ban and permit geologic storage for hard-to-abate emitters. This study presents a static screening and assessment of Austria’s CCS and underground hydrogen storage (UHS) potential in hydrocarbon reservoirs. Using reported ultimate recoveries from oil and gas fields, CO2 storage capacities were estimated across 73 reservoirs. The results indicate a total static CCS capacity of 263 Mt (183–357 Mt, depending on efficiency factor variation) for pure CO2, which decreases to 151–293 Mt when high levels of impurities are considered. The five largest gas fields, with individual storage capacities exceeding 10 Mt, account for approximately 100 Mt of CCS capacity. Site-specific challenges in Austria’s largest hydrocarbon fields may include numerous abandoned boreholes, strong aquifer support, and competition with UHS. Storage efficiency factors and CO2 density variations significantly impact capacity estimates, particularly in reservoirs near the supercritical threshold. For UHS, the total theoretical storage capacity across suitable fields was calculated to be 55 TWh, with 21 TWh identified in operational underground gas storage sites. Competition between CCS and UHS technologies is anticipated in relatively large gas fields with overlapping suitability. While individual CO2 storage capacities in hydrocarbon fields are small compared to offshore saline aquifers, they offer advantages such as existing infrastructure, detailed reservoir characterization, and proximity to major emission sources. The identified CCS capacity could bridge crucial periods before CO2 export or saline aquifer storage becomes viable.

Rock heterogeneity has a significant effect on immiscible displacement. This is especially true when the mobility ratio of the two fluids is unfavorable, favoring unstable displacement. However, this is not taken into account in the numerical analysis of classical core flooding experiments to quantify two-phase flow properties using Special Core Analysis (SCAL). Our approach combines the modern interpretation of SCAL data with experimental data measured on rock samples for which the homogeneity assumption - a prerequisite for SCAL experiments - can no longer apply due to their size and heterogeneity. In contrast to other studies that take heterogeneities into account, we focus on simple-to-perform unsteady-state experiments. We analyze these experiments by numerical interpretation using homogeneous and heterogeneous simulation domains and by introducing porosity-based heterogeneity and permeability as well as capillary scaling. In the current study, we first question the applicability of standard relative permeability measurements to heterogeneous rocks and fluids with an excessively high mobility ratio, such as for CO2-brine displacement in heterogeneous rocks. However, we show that they describe two-phase flow very well when porosity-based heterogeneity is taken into account, which is equivalent to downscaling. The study thus shows a way to fall back on established standard measurements if it should be possible to account for subgrid heterogeneities in SCAL workflows. To this end, we propose an approach based on steady-state experiments and appropriate sample selection.

Investigating the subsurface potential for hydrogen methanation requires detailed knowledge of the reservoir, formation brine, microbial abundance, and fluid transport properties at multiple scales. This study focuses on the impact of microbial growth-induced changes in the hydraulic properties of porous media during geomethanation. Microfluidic experiments were conducted in a novel microfluidic setup offering high spatial and temporal resolution to analyze microbial colonization and biomass permeability using a chemically defined mimic of the formation brine. A brine-saturated pore network was incubated with methanogenic cultures native to underground gas storages, including an autochthonous consortium from a geo-methanation field trial in the Upper Austrian Molasse Basin and the hydrogenotrophic methanogen Methanobacterium formicicum. High-resolution time-lapse imaging and differential pressure measurements were used to characterize biomass-induced changes in permeability and porosity. Despite significant biomass accumulation and porosity reduction, the emergence of flow channels preserved a large fraction of the original permeability. Numerical pore-scale simulations revealed an intrinsic biomass permeability on the order of 100 mD, supporting the experimental findings. These results have critical implications for the methanation process: (1) The formation of preferential flow paths may prevent complete bio-clogging, sustaining substrate supply and microbial activity. (2) High intrinsic biomass permeability supports advective nutrient transport, maintaining high gas conversion rates. (3) Methanobacterium formicicum exhibits a denser accumulation and a greater impact on the permeability than the natural microbial consortium.

This study investigates the fundamental ion-specific (Na+, Cl-, Mg2+, and SO42-) interactions governing a polar model oil (decane + benzoic acid) at the calcite/carbonated brine interface by adopting a fully atomistic molecular dynamics (MD) simulation. By bridging molecular-scale interactions with macroscopic mechanisms, such as interfacial tension (IFT) reduction, oil viscosity, and wettability changes, this work provides the first direct mechanistic validation of phenomena that have previously been inferred only from experimental observations in carbonated smart water flooding systems. The results demonstrate that enhanced interactions between carboxylic acids and anions at the oil/brine interface significantly influence CO2 diffusion and distribution within the oleic phase, which affects the apparent oil viscosity. While variations in brine ionic composition cause only modest changes in IFT, a pronounced reduction is observed with increased concentrations of polar molecules in the oil phase. Structural analysis reveals that divalent ions (Mg2+, SO42-) are excluded from the hydration layers near the calcite surface but alter the arrangement of Na+ and Cl- ions in the hydration layer covering the calcite surface, thereby influencing wettability. Notably, SO42- neutralizes the calcite surface positive charge and facilitates Mg2+ access to the interface, promoting desorption of benzoic acid (BA) from the surface through the Mg-BA association. This highlights the cooperative role of SO42- and Mg2+ in releasing polar species from the calcite surface. The findings underscore the dominant influence of IFT over contact angle in capillary-driven recovery and show that apparent viscosity is more sensitive to CO2 content and overall salinity than specific ions. Therefore, from an industrial perspective, maintaining seawater-like salinity enriched with divalent ions offers a practical strategy to enhance the mobilization of polar acidic components during carbonated water flooding in carbonate reservoirs, supporting the design of more efficient Enhanced Oil Recovery (EOR) formulations.

Underground hydrogen storage (UHS) has attracted increasing attention as a promising technology for the largescale storage of renewable energy resources and the decarbonization of energy systems. This study aimed to identify critical parameters influencing UHS performance, particularly the role of hydrogen conversion via in situ methanation and hydrogen recovery during production cycles. The main focus is the Lehen field in Upper Austria, where a pilot hydrogen storage project was conducted under the leadership of RAG Austria AG. A layered reservoir model was developed on the basis of well-log data to simulate the field trials that occurred in 2016. A sensitivity analysis was performed with the one-parameter-at-a-time (OPAAT) method and the response surface methodology (RSM) to evaluate the impacts of different parameters on hydrogen methanation and hydrogen recovery. The RSM results indicate the activation energy as the most influential factor on methanation that accounts for similar to 20,000 moles variation in generated methane, significantly higher than the 6000 moles variance observed in OPAAT. However, initial CO2 content contributes up to 15,000 moles of methane generation as per RSM, whereas OPAAT results in a larger impact of up to 32,000 moles. These discrepancies demonstrate the limitations of isolated parameter analyses like OPAAT, which may not accurately capture the complex interactions between factors influencing the methanation process. This research provides valuable insights for optimizing UHS performance by emphasizing the influence of reservoir parameters on storage efficiency. In addition, a robust workflow for conducting comprehensive sensitivity analyses of UHS systems is established. By understanding these key factors, the potential and predictability of large-scale UHS systems can be significantly improved.

In the context of CO2 injection wells, several factors have the potential to compromise well injectivity, which under the most unfavorable circumstances can result in well loss. These factors include formation, drying and salt precipitation. The degree of scaling is primarily determined by capillary transport phenomena due to evaporation kinetics, effects that are largely ignored in reservoir simulators. In the present work, we have developed and implemented drying and evaporation kinetics in a reactive continuum transport model based on DuMuX. The model considers all aspects of the processes, including capillary-driven countercurrent transport of dissolved solids and their subsequent precipitation. This comprehensive approach allows the model to provide a realistic description *of the processes occurring in the borehole environment. In cases where experimental data sets were incomplete, a qualitative comparison was made between the model and the available experimental data sets. Stochastic sensitivity analysis was used to identify the key parameters that define the zone of countercurrent flow and the potential for formation damage. The work thus provides a model capable of realistically simulating formation drying, including drying and precipitation kinetics. In the case of supercritical CO2 injection and for an assumed homogeneous sandstone formation, the mutual mass transfer coefficient, the salinity, and the injection rate were found to be the most influential parameters in determining the ultimate salt precipitation along the core sample and the respective size of the drying zone. In contrast to the results of the equilibrium model, the results of our model indicate a more uniform distribution of salt precipitates throughout the core.

CO2 injection in deep saline aquifers is at the verge between viscous-stable and viscous-unstable displacement and can therefore potentially lead to viscous fingering. An unstable displacement impairs the sweep efficiency in many ways and thus the storage capacity and storage safety. An assessment of the consequences and, if necessary, of measures to be taken requires an estimate of the finger size, expressed as the finger wavelength. However, the existing models contradict each other by orders of magnitude.

The structural and dynamic properties of fluids under confinement in a porous medium differ from their bulk properties. This study delves into the surface structuring and hydrodynamic characteristics of oil/thin film carbonated brine two-phase within a calcite channel upon salinity variation. To this end, both equilibrium and non-equilibrium molecular dynamics simulations are utilized to unveil the effect of the carboxylic acid component (benzoic acid) in a simple model oil (decane) confined between two thin films of carbonated brine on the oil-brine-calcite characteristics. The salinity effect was scrutinized under four saline carbonated waters, deionized carbonated water (DCW), carbonated low-salinity brine (CLSB, 30,000 ppm), carbonated seawater (CSW, 60,000 ppm), and carbonated high-salinity brine (CHSB, 180,000 ppm). An electrical double layer (EDL) is observed at varying salinities, comprising a Stern-like positive layer (formed by Na+ ions) followed by a negative one (formed by Cl- ions primarily residing on top of the adsorbed sodium cations). By lowering the salinity, the Na+ ions cover the interface regions (brine-calcite and brine-oil), depleting within the brine bulk region. The lowest positive surface charge on the rock surface was found in salinity corresponding to seawater. Two distinct Na+ peaks at the oleic phase interface have been observed in the carbonated high-salinity brine system, enhancing the adsorption of polar molecules at the thin brine film interfaces. There is a pronounced EDL formation at the oleic phase interface in the case of CSW, resulting in a strong interface region containing ions and functional fractions. Likewise, the oil region confined by CSW exhibited the lowest apparent viscosity, attributed to the optimized salinity distribution and inclination of benzoic acid fractions uniformly at the brine-oil interface, acting as a slippery surface. Moreover, the results reveal that the presence of polar fractions could increase the oil phase's apparent viscosity, and introducing ions to this system reduces the polar molecules' destructive effect on the apparent viscosity of the oil region. Therefore, the fluidity of confined systems is modulated by both composition of the brine and oil phases.

This study delves into the properties and behavior of xanthan TNCS-ST, a specialized variant designed for enhanced oil recovery (EOR) purposes. A notable aspect of this polymer is its transparency and capability to dissolve in high salt concentrations, notably up to 18% total dissolved solids. Various laboratory methods are employed to assess the polymer’s distinctive traits, including transparency, salt tolerance, and high pyruvylation. These methods encompass preparing xanthan solutions, conducting filtration tests, assessing energy consumption, and measuring rheological properties. The findings highlight the influence of salt concentration on xanthan’s filterability, indicating increased energy requirements for dissolution with higher salt and xanthan concentrations. Additionally, this study observes temperature-dependent viscosity behavior in different solutions and evaluates the shear stability of xanthan. A significant and novel characteristic of TNCS-ST is its high salt tolerance, enabling complete dissolution at elevated salt concentrations, thus facilitating the filterability of the xanthan solution with sufficient time and energy input. Core flooding experiments investigate fluid dynamics within porous rock formations, particularly sandstone and carbonate rocks, while varying salinity. The results underscore the substantial potential of the new xanthan polymer, demonstrating its ability to enhance oil recovery in sandstone and carbonate rock formations significantly. Remarkably, the study achieves a noteworthy 67% incremental recovery in carbonate rock under the high salinity level tested, suggesting promising prospects for advancing enhanced oil recovery applications.

This study examines the connections between various fracture indicators and production data with an example from one of the giant fields in the Middle East producing complex fractured carbonate lithologies. The field under study hosts two reservoirs with a long development and production history, including carbonates from the Asmari and Bangestan Formations. A fracture intensity map was generated based on the interpretation of image logs from 28 wells drilled within the field. Mud loss data were collected and mapped based on the geostatistical Gaussian Random Function Simulation (GRFS) algorithm. Maximum curvature maps were generated based on Asmari structural surface maps. Comparing the results shows a good agreement between the curvature map, fault distribution model, mud loss map, fracture intensity map, and productivity index. The results of image log interpretations led to the identification of four classes of open fractures, including major open fractures, medium open fractures, minor open fractures, and hairline fractures. Using the azimuth and dip data of the four fracture sets mentioned above, the fracture intensity log was generated as a continuous log for each well with available image log data. For this purpose, the fracture intensity log and a continuous fracture network (CFN) model were generated. The continuous fracture network model was used to generate a 3D discrete fracture network (DFN) for the Asmari Formation. Finally, a 3D upscaled model of fracture dip and azimuth, fracture porosity, fracture permeability, fracture length, fracture aperture, and the sigma parameter (the connectivity index between matrix and fracture) were obtained. The results of this study can illuminate the modeling of intricate reservoirs and the associated production challenges, providing insights not only during the initial production phase but also in the application of advanced oil recovery methods, such as thermal recovery.

Summary Structural and stratigraphic trapping of a Carbon Capture and Storage (CCS) site depends on the primary CO2 migration in the field, whereas residual CO2 trapping is a secondary process as water re-imbibes the volumes. These mechanisms are highly important for safe storage and set the scene for solubility trapping and final mineralization. Computational methods such as pore-network modeling and morphological methods (PMM) are now available for computing capillary pressure and relative permeability saturation functions. This research project aims to develop an efficient methodology to characterize rock properties from pore-to-log-to-seismic scale, to describe the reactive transport and trapping of CO2 in relevant subsurface rock formations. Available OMV data is used from CO2 storage candidate sites. The PMM will be refined and verified for its technical readiness for the proposed topic. In addition, we develop a workflow for approaching the application of the PMM to CO2 flooding of aquifers and depleted hydrocarbon reservoirs. The innovative aspects include refining the existing PMM, understanding pore-scale displacements in multi-phase flow, and making the first step towards field application. The first results of the two-year research project are presented. They provide a solid framework for the upscaling workflow being developed in the second year.

This study utilized molecular dynamics simulations to understand the liquid/liquid interfaces in a natural environment involving carbon dioxide and various acidic components. The aim is to unravel the impact of polar fractions with various chemical structures and functional groups, namely benzoic acid, decanoic acid, phenol, and decanol, on the interfacial phenomena of the oleic phase (decane) in contact with water or CO2-rich water at the molecular resolution. The findings indicate that carbon dioxide molecules enrich at the decane/water interface before dissolving into the oleic phase. When polar molecules are introduced to the oleic phase, there is a competition between carbon dioxide and acidic components to accumulate at the interface. The functional hydrocarbon fractions displace carbon dioxide at the interface and bridge the oleic and aqueous phases, reducing interfacial tension. Polar components change the charge distribution of water molecules in the biphasic system, signifying that the organized water layer at the interface with the non-aqueous phase has been disrupted. In contrast to the polar molecules, the carbon dioxide tends to diffuse into the oleic phase and changes the bulk properties like oil fluidity. Accordingly, the fluidity of the decane exhibited significant enhancement by CO2 diffusion throughout the bulk oil phase, which might lead to substantial viscosity reduction.

Underground biomethanation, which relies on the subsurface microbial activity to convert hydrogen and carbon dioxide into methane, is a promising approach to support carbon capture, utilization, and storage technology. The process involves injecting hydrogen with captured CO2 into depleted oil and gas reservoirs or aquifers colonized by hydrogenotrophic methanogens that can convert these two substrates into methane. Despite the attractiveness of this technology, there are still uncertainties about the efficiency of the conversion process, particularly the impact of microbial parameters. To investigate the efficiency of the hydrogen conversion process, we relied on a bio-reactive transport model that can mimic microbial growth and decay, consumption of substrates, and transport of reactants and products. It was found that the methane concentration peaks near the injection well when the hydrogen fraction is in the range of 75% to 80% of the injected gas composition. In addition, a noticeable hydrogen sulfide concentration can be produced due to sulfide ions in the brine. Using the Kozeny-Carman relation, an attempt was made to correlate microbial growth with reduced porosity and permeability. It was then revealed that substrate consumption by microbes leads to a drastic increase in the microbial population in the subsurface, which can reduce the petrophysical properties of the reservoir, especially in the near wellbore area. The results obtained from a series of parametric analyses showed that the hydrogen concentration in the injected gas, pressure, well spacing, and injection rate are some of the most important parameters contributing to the biomethanation process. (c) 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Naturally fractured reservoirs are indescribable systems to characterize and difficult to produce and forecast. For the development of such reservoirs, the role of naturally forming fractures in the different development stages needs to be recognized, especially for the pressure maintenance and enhanced oil recovery stages. Recent development in the field of naturally carbonate fractured aimed at fracture characterization, fracture modeling, and fracture network impact of fracture networks on oil recovery were reviewed. Consequently, fracture identification and characterization played pivotal roles in understanding production mechanisms by integrating multiple geosciences sources and reservoir engineering data. In addition, a realistic fracture modeling approach, such as a hybrid, can provide a more accurate representation of the behavior of the fracture and, hence, a more realistic reservoir model for reservoir production and management. In this respect, the influence of different fracture types present in the reservoir, such as major, medium, minor, and hairline fractures networks, and their orientations were found to have different rules and impacts on oil production in the primary, secondary, and EOR stages. In addition, any simplification or homogenization of the fracture types might end in over or underestimating the oil recovery. Improved fracture network modeling requires numerous considerations, such as data collection, facture characterization, reservoir simulation, model calibration, and model updating based on newly acquired field data are essential for improved fracture network description. Hence, integrating multiple techniques and data sources is recommended for obtaining a reliable reservoir model for optimizing the primary and enhanced oil recovery methods.

Numerous reservoirs that play a significant role in worldwide petroleum production and reserves contain fractures. Typically, the fractures must form a connected network for a reservoir to be classified as naturally fractured. Characterizing the reservoir with a focus on its fracture network is crucial for modeling and predicting production performance. To simplify the solution, dual-continuum modeling techniques are commonly employed. However, to use continuum-scale approaches, properties such as the average aperture, permeability, and matrix fracture interaction parameters must be assigned, making it necessary to improve the fracture depiction and modeling methods. This study investigated a fractured reservoir with a low matrix permeability and a well-connected fracture network. The focus was on the impact of the hierarchical fracture network on the production performance of gas-based enhanced oil recovery methods. The discrete fracture network (DFN) model was utilized to create comprehensive two-dimensional models for three processes: gas injection (GI), water alternating gas (WAG), and foam-assisted water alternating gas (FAWAG). Moreover, dimensionless numbers were employed to establish connections between properties across the entire fracture hierarchy, spanning from minor to major fractures and encompassing the fracture intensity. The results indicate that the FAWAG process was more sensitive to fracture types and networks than the WAG and GI processes. Hence, the sensitivity of the individual EOR method to the fracture network requires a respective depth of description of the fracture network. However, other factors, such as reservoir fluid properties and fracture properties, might influence the recovery when the minor fracture networks are excluded. This study determined that among the enhanced oil recovery (EOR) techniques examined, the significance of the hierarchical depth of fracture networks diminished as the ratio of major (primary fracture) aperture to the aperture of medium and minor fractures increased. Additionally, the impact of the assisted-gravity drainage method was greater with increased reservoir height; however, as the intensity ratio increased, the relative importance of the medium and minor fracture networks decreased.

The morphological approach is a computationally attractive method for calculating relative permeability and capillary pressure saturation functions. In the corresponding workflow, morphological operations are used to calculate the fluid phase distribution in the pore space of a digital twin. Once the pore space is occupied, the conductivity of the individual fluid phases and thus the relative permeability can be calculated by direct flow simulations. It therefore combines computationally favorable geometric operations with direct flow simulations. In contrast to pore network modeling, all calculations are directly performed on the digital twin without abstraction of the pore space. While the morphological operations conceptually correctly describe primary drainage processes and delivers good results, the method so far failed to describe imbibition processes and the influence of wettability. In this work, we implement contact angle distributions in a deterministic and stochastic way. In this manner, we extend the simulated saturation range from purely spontaneous to forced imbibition, resulting in a full-range imbibition relative permeability. Furthermore, by introducing stochastic contact angle distributions, different fluid phase distributions are obtained, which now allow for an uncertainty analysis. To verify the simulation results, we check (a) whether the simulation results agree with SCAL measurements and (b) compare morphologically and experimentally derived results on the pore scale. With the newly introduced concepts, the imbibition process behaves as physically expected, and shows a good agreement with experimentally derived relative permeability curves and microscopic fluid-phase distributions.

Pore-scale properties can be obtained by building a reliable digital twin of porous media through the digital rock physics (DRP) workflow. The two prerequisites of DRP are reliable imaging and computing power. Determining a proper image resolution that can reveal the actual pore-scale properties is challenging as there is a trade-off between the resolution and the representative elementary volume (REV). The REV is the smallest volume that reproduces the properties of the whole porous medium. The REV is a function of heterogeneities on the pore scale, the parameter of interest, and the scale range. Although the REV analysis for hydraulic properties is straightforward, it is computationally expensive. This study aims to estimate hydraulic pore-scale properties during REV evaluations by the geometric characterization of porous media using the Minkowski morphological functionals. Two sandstone and one carbonate rock samples were scanned at multiple imaging resolutions by both laboratory and synchrotron tomography. The REVs of various parameters of interest (porosity, permeability, surface area, tortuosity, Minkowski functionals) were computed, and the effect of image resolution and artificial rebinning on the final REV values was examined. After reaching the REV for porosity, the REV for the integrals of mean and total curvature agreed well with the permeability REV for large-volume image sizes. At constant porosity, the Minkowski integrals were found to be indicators for pore throat sizes. We also showed that the properties obtained from the rebinned (or coarsened) images differ entirely from that of actual scans at the same resolution.

Multiphase flow in porous media is relevant in many areas of geoenergy engineering and is governed by relative permeability and capillary pressure saturation functions. These functions are key uncertainties in reservoir engineering and their measurement is demanding and resource intensive. Despite the experimental effort, it is not yet common practice to numerically interpret the data, nor is it common practice to investigate their uncertainty. Furthermore, data interpretation is limited to power-law functions, which is insufficient for describing complex rock types such as microscopically heterogeneous carbonates. We developed a MATLAB-MRST-based simulator for simultaneous interpretation of data sets from different experimental techniques. We discuss the implementation of the common parametrized relative permeability representations and their deficiency to describe data from complex rocks. To overcome this limitation, a point-by-point approach is developed and applied to an extensive carbonate data set. For uncertainty analysis, a Markov Chain Monte Carlo sampling-based workflow is implemented and applied. The uncertainty is discussed in the frame of the individual data set, simultaneously analyzed data sets, and the sample-to-sample variation. The developed method makes the interpretation of relative permeability and capillary pressure saturation functions conclusive, especially in cases of complex line shapes, and is an essential step toward uncertainty-driven stochastic reservoir modeling.