Capillary Threshold Pressure Research Articles

Variation of thickness, internal structure and petrophysical properties in a deformation band fault zone in siliciclastic rocks

We studied the geometry and petrophysical properties of fault core and damage zones of a deformation band fault zone in the arkosic sandstones of the Cretaceous Antenor Navarro Formation in the Rio do Peixe Basin, Brazil. The present work includes results from fieldwork and laboratory measurements. We performed structural, geometric, and permeability measurements in the field. These measurements were performed on a longitudinal scanline along the fault core and 18 orthogonal scanlines crossing both fault core and damage zones in the footwall and hanging wall. Drone images were taken from the field locality to study the geometric relation between fault core and individual deformation bands in the damage zone. Porosity, capillary pressure and grain size analyses were performed on the samples. The studied fault is normal and composed of three linked segments, a central E-W segment which is hard-linked to two NE-SW segments tipping toward east and west. Our results show that fault core is the thickest on the E-W segment. The damage zone is narrower around the central part (E-W segment) of the fault and widens westward in both hanging wall and footwall, beyond this point the hanging wall damage zone is wider than the footwall damage zone. The thickest part of fault core has the lowest porosity and permeability and the highest capillary threshold pressure, therefore, increasing the fault sealing capacity. Permeability measurements parallel and perpendicular to fault dip show an anisotropy, in which the permeability perpendicular to fault dip is one order of magnitude lower than dip-parallel permeability measurements. This work highlights the effect of hard linkage between the E-W and NE-SW segments of the studied fault on the petrophysical properties of fault rocks and emphasizes the influence of such linkage on hampering the fluid flow along the breached segment of the fault.

Numerical modelling of long-term CO2 storage mechanisms in saline aquifers using the Sleipner benchmark dataset

We present numerical modelling of long-term CO2 storage in saline aquifers using field dataset in the Sleipner carbon capture and storage project in offshore Norway. A compositional reservoir simulation model was constructed for an entire section of the reservoir whose thickness is approximately 200 m. We used a fine grid system with a thickness of down to 0.2 m to capture thin intraformational mudrock barriers which can play an important role in the upward migration of injected CO2 as observed in 4D seismic datasets. The threshold capillary pressure and vertical permeability of these mudrock barriers were tuned to have nine separated CO2 plumes below the mudrock layers as observed in the corresponding seismic data. The mismatches in the CO2 plume between our simulation result and 4D seismic observation suggested further model tuning. The simulation was extended without further CO2 injection. During CO2 injection, the dominant storage mechanism was structural trapping, which was influenced by the properties of intraformational mudrock barriers. After the end of CO2 injection, the amount of residual gas trapping started to increase. The significant change in the storage mechanisms occurred during a period of 20 years after shut-in. At 100 years and onward, solubility trapping took effect with the decrease of residually trapped CO2. Mass diffusion of CO2 in formation brine controlled the degree of the invasion of CO2 into the cap rock over 1000 years of our simulation limit.

Influence of capillary threshold pressure and injection well location on the dynamic CO2 and H2 storage capacity for the deep geological structure

The subject of this study is the analysis of influence of capillary threshold pressure and injection well location on the dynamic CO2 and H2 storage capacity for the Lower Jurassic reservoir of the Sierpc structure from central Poland. The results of injection modeling allowed us to compare the amount of CO2 and H2 that the considered structure can store safely over a given time interval. The modeling was performed using a single well for 30 different locations, considering that the minimum capillary pressure of the cap rock and the fracturing pressure should not be exceeded for each gas separately.Other values of capillary threshold pressure for CO2 and H2 significantly affect the amount of a given gas that can be injected into the reservoir. The structure under consideration can store approximately 1 Mt CO2 in 31 years, while in the case of H2 it is slightly above 4000 tons. The determined CO2 storage capacity is limited; the structure seems to be more prospective for underground H2 storage. The CO2 and H2 dynamic storage capacity maps are an important element of the analysis of the use of gas storage structures. A much higher fingering effect was observed for H2 than for CO2, which may affect the withdrawal of hydrogen. It is recommended to determine the optimum storage depth, particularly for hydrogen. The presented results, important for the assessment of the capacity of geological structures, also relate to the safety of use of CO2 and H2 underground storage space.

Pore-scale study of in-situ surfactant flooding with strong oil emulsification in sandstone based on X-ray microtomography

This study presented a pore-scale investigation on the dynamic displacement of oil subjected to ex-situ and in-situ surfactant flooding using X-ray microtomography. The ex-situ surfactant solution was pre-prepared, whereas the in-situ surfactant was generated directly with the chemical reaction inside porous media. The results showed that oil removal from the pore spaces relied on the combination of piston-like, pore-body filling and a weak emulsification mechanism in the ex-situ system, whereas the in-situ system was dominated by a strong emulsification process. The threshold capillary pressure was decreased significantly owing to interfacial tension reduction and wettability alteration, which enhanced the oil cluster mobilization. Therefore, the in-situ system produced the highest oil recovery efficiency of 86.9% compared with ex-situ system and water flooding. The emulsifying ability was evaluated through oil cluster size distributions and their dynamic evolution. The networks or branches disappeared and emulsified into small oil ganglia and singlets, thereby leading to a significant decrease in the average equivalent diameter. Finally, strong emulsification in the in-situ system was attributed to quick and precise surfactant aggregation at the oil–water interface that induced blebbing, whereas the ex-situ case was dominated by slow surfactant transport relying on advection and diffusion in the flow mainstream.

Effect of Displacement Pressure on Oil-Water Relative Permeability for Extra-Low-Permeability Reservoirs.

The oil–water relative permeability is an important parameter to characterize the seepage law of fluid in extra-low-permeability reservoirs, and it is of vital significance for the prediction and evaluation of the production. The pore throat size of extra-low-permeability reservoirs is relatively small, and the threshold pressure gradient and capillary pressure cannot be negligible. In this study, the oil–water relative permeability experiments with three different displacement pressures were carried out on the same core from the extra-low-permeability reservoir of Chang 4+5 formation in Ordos basin by the unsteady experimental method. The results show that the relative permeability of oil increases, while the relative permeability of water remains unchanged considering the capillary pressure and oil threshold pressure gradient compared with the JBN method. As the displacement pressure enlarges, the relative permeability of oil and water both increases; the residual oil saturation decreases, therefore the range of the two-phase flow zone is improved. Moreover, the isotonic point of water–oil relative permeability curves moves to the upper right region, and the reference permeability improves as well with the increasing pressure.

Impact of hydrogen solubility on depleted gas field's caprock: an application for underground hydrogen storage

Depleted gas fields are considered a low-risk location for underground hydrogen storage purposes to balance seasonal fluctuations in hydrogen supply and demand. The objective of this study was to identify any significant risk of hydrogen leakages stored in depleted gas fields. The capability of the storage area in terms of sealing efficiency varies with parameters such as rate of diffusion, solubility, thickness and capillary threshold pressure of the caprock. The most common caprock are shales, which contain organic material. The solubility of hydrogen into organic material could change the petrophysical properties of the rock, such as porosity and permeability. Any changes in these petrophysical characteristics can reduce the capillary threshold pressure thus reducing the caprock efficiency for the safe storage of hydrogen. There is about 20% of the remaining gas volume in the depleted gas field, which helps to prevent brine from entering the production streamlines and maintain reservoir pressure. The characteristic data of hydrogen at different high pressures and temperatures have been evaluated and imported into the simple finite element model using the Python programming language. Most of the parameters that influence reducing the strength of the caprock are identified. Crucial parameters are the rate of diffusion, the solubility of hydrogen in kerogen, geomechanical deformation, threshold capillary pressure, long period of injection and withdrawing of hydrogen. The model shows that the native gas production with hydrogen is low due to significant density variation and mobility ratio between methane and hydrogen. Finally, a wide range of parameters and reservoir conditions has been considered for minimising the potential risks of possible leakages.

Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO 2 systems

Fault seal analysis is a key part of understanding the hydrocarbon trapping mechanisms in the petroleum industry. Fault seal research has also been expanded to CO 2 –brine systems for the application to carbon capture and storage (CCS). The wetting properties of rock-forming minerals in the presence of hydrocarbons or CO 2 are a source of uncertainty in the calculations of capillary threshold pressure, which defines the fault sealing capacity. Here, we explore this uncertainty in a comparison study between two fault-sealed fields located in the Otway Basin, SE Australia. The Katnook Field in the Penola Trough is a methane field, while Boggy Creek in Port Campbell contains a high-CO 2 –methane mixture. Two industry standard fault seal modelling methods, one based on laboratory measurements of fault samples and the other based on a calibration of a global dataset of known sealing faults, are used to discuss their relative strengths and applicability to the CO 2 storage context. We identify a range of interfacial tensions and contact angle values in the hydrocarbon–water system under the conditions assumed by the second method. Based on this, the uncertainty related to the spread in fluid properties was determined to be 24% of the calculated threshold capillary pressure value. We propose a methodology of threshold capillary pressure conversion from hydrocarbons–brine to the CO 2 –brine system, using an input of appropriate interfacial tension and contact angle under reservoir conditions. The method can be used for any fluid system where fluid properties are defined by these two parameters. Supplementary material: (1) Fault seal modelling methods and calculations, and (2) hydrocarbon and CO 2 interfacial tensions and contact angle values collected in the literature are available at https://doi.org/10.6084/m9.figshare.c.4877049 This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series

Key controls on hydrocarbon retention and leakage from structural traps in the Hammerfest Basin, SW Barents Sea: implications for prospect analysis and risk assessment

Evidence of hydrocarbon leakage has been well documented across the SW Barents Sea and is commonly associated with exhumation in the Cenozoic. While fault leakage is thought to be the most likely cause, other mechanisms are possible and should be considered. Further study is required to understand what specific mechanism(s) facilitate such leakage, and why this occurs in some locations and not others. In a case study of the Snøhvit Field, we use seismic and well data to quantify fault- and top-seal strength based on mechanical and capillary threshold pressure properties of fault and cap rocks. Magnitude and timing of fault slip are measured to acknowledge the role that faults play in controlling fluid flow over time. Results based on theoretical and in situ hydrocarbon column heights strongly indicate that across-fault and top-seal breach by capillary threshold pressure, and top-seal breach by mechanical failure are highly unlikely to have caused hydrocarbon leakage. Instead, top-seal breach caused by tectonic reactivation of identified faults is likely to have facilitated hydrocarbon leakage from structural traps. The results of this case study acknowledge the different mechanisms by which hydrocarbons can leak from a structural trap. Employing both a holistic and quantitative approach to assessing different seal capacities reduces the likelihood that a particular cause of hydrocarbon leakage is overlooked. This is particularly relevant for the Snøhvit Field in its dual capacity as a producing gas field and as a carbon sequestration site since both systems rely on a thorough understanding of seal capacity and leakage potential.

The Effect of Supercritical CO2 on Shaly Caprocks

The effect of supercritical CO2 on the shaly caprocks is one of the critical issues to be considered in CO2 sequestration programs. Shale-scCO2 interactions can alter the seal integrity, leading to environmental problems and bringing into question the effectiveness of the program altogether. Several analytical studies were conducted on samples from Jurassic Eneabba Basal Shale and claystone rich facies of the Triassic Yalgorup Member (725–1417 m) in the Harvey CO2 sequestration site, Western Australia, to address the shale-scCO2 interactions and their effect on the petrophysical properties of the caprock. Shale samples saturated with NaCl brine were exposed to scCO2 under the reservoir condition (T = 60 °C, P = 2000 psi) for nine months and then tested to determine their altered mineralogical, petrophysical and geochemical properties. The experimental study examined changes to the mineralogical composition, capillary threshold pressure, and pore size distribution (PSD) of samples. The X-ray diffraction (XRD) results showed several changes in mineralogy because of rock-brine-CO2 reactions. Quartz, feldspars, kaolinite, and goethite were dissolved in most samples and muscovite, and halite were precipitated in general. Nuclear magnetic resonance (NMR), low-pressure nitrogen adsorption (LPNA), and mercury injection capillary pressure (MICP) tests indicate an increase in pore volume, except for relatively tighter, clay-rich samples. A reduction in capillary threshold pressures of samples after exposure to scCO2 is observed.

Pore-scale study of fluids flow and fluid-fluid interactions during near-miscible CO2 EOR and storage in oil reservoirs

SummaryCO2 injection in oil reservoirs has been widely accepted as an effective EOR and CO2 storage technique. While oil recovery and CO2 storage potential of this technique at the core scale has been widely studied, complex fluids flow and fluid-fluid interactions at the pore-scale during nearmiscible CO2 injection require further study. For this aim, a unique high-pressure and high-temperature microfluidic system was used to conduct experiments at 2,500 psi and 40°C using live reservoir crude oil.According to results, during tertiary CO2 injection, due to the positive value of spreading coefficient, CO2 flowed only inside the oil and oil spread over CO2 and prevented CO2 contact the water. Due to unfavourable mobility ratios and permeability heterogeneities, displacement during tertiary CO2 flooding was unstable and viscous fingering occurred which led to an early breakthrough of CO2 and bypassing of a large amount of oil. However, after CO2 breakthrough, CO2 gradually started to flow inside the bypassed oil zones in the transverse/backward directions which is a characteristic of capillary fingering. Due to the gradual diffusion of CO2 into the bypassed oil, IFT between oil and CO2 decreased which led to a reduction of threshold capillary pressure, thus CO2 (non-wetting phase) entered the bypassed oil-filled pores. As a result of this unique mechanism, oil recovery after CO2 breakthrough significantly increased and almost all the bypassed oil was produced. The extent of this oil recovery mechanism depends on the extent of CO2-oil IFT reduction which depends on injection pressure.During CO2 flow in pores, CO2 displaced the water through multiple displacement mechanism. CO2 displaced the oil in the open-end pores thorough bulk flow, and the spreading oil layers were gradually produced by film flow. Uniquely, CO2 produced the oil in dead-end pores through a mix of bulk flow and film flow.The outcomes of this study provide an in-depth understanding of fluids flow and fluid-fluid interactions during near-miscible CO2 EOR-storage.

Estimation of Capillary Pressure in Unconventional Reservoirs Using Thermodynamic Analysis of Pore Images

AbstractUnconventional reservoirs comprise a growing portion of producible reserves due to increasing knowledge of their nature as well as significant advances in production technology. The development of advanced pore‐scale modeling techniques presents potential for better estimation of reservoir flow characteristics including relative permeability, saturation distributions, and capillary pressure. Although pore‐scale network models take into account the pore throat connections and the appropriate fluid properties, highly simplified pore cross‐sectional shapes are still employed when estimating the threshold capillary pressure for fluid‐fluid displacements in each pore element. As a result, there is a growing need for more realistic threshold capillary pressure estimates generated using pore geometries that honor the real pore topology. To this end, a semianalytical model is presented that allows the prediction of threshold capillary pressure as well as the capillary pressure versus saturation relationship for piston‐like fluid displacements using images of unconventional reservoir rock samples. The model was validated on three different idealized pore geometries and compared against available analytical solutions, resulting in an error of less than 1% for all cases. The model was compared to experimental data using fluid occupancy maps obtained using an X‐ray nano‐CT scanner during an oil imbibition sequence into a miniature reservoir shale sample. The capillary pressure versus wetting phase saturation relationship was also determined for a 2‐D focused ion beam scanning electron microscopy image slice. The presented model shows promise for enabling more advanced pore‐scale modeling of shale rock.

Pore-scale network modeling of microporosity in low-resistivity pay zones of carbonate reservoir

Archie's law is commonly used for the estimation of brine saturation using electrical conductivity of sedimentary rock. For a formation with narrow pore size distribution (PSD), low resistivity could mean high water saturation and hence, high water production. This, however, is not the case for many formations with wide PSDs, for which Low Resistivity Pay (LRP) zones have been reported with very low or none water cut production. One of the main causes resulting in LRP zones, especially in carbonates, is the existence of wide PSDs. Due to their small sizes, micro-pores have much higher threshold capillary pressures during drainage in a water-wet sample. In these systems, oil as the non-wetting phase preferably occupies larger pores leaving micro-pores saturated with brine. The existence of connected pathways through micro-pores that are fully saturated with a conductive phase (i.e., brine) creates ‘shortcuts’ for the electrical current which causes a short circuit and, ultimately, lowers rock resistivity measured from logs. Here in this work, we investigate the impact of microporosity on the electrical properties of porous media under multiphase flow conditions. We develop a pore-scale network model for the simulation of displacement sequences during drainage and imbibition in the presence of micro-pore networks. To do so, we first construct ‘macro’ networks on 2D rectangular lattices which are later altered to include micro-pores. A comprehensive set of sensitivity analyses is performed to assess the impact of various parameters including the tortuosity, geometry, and location of the microporosity (i.e., parallel or in series, continuous or non-continuous). Also, 3D networks for two different rock samples are used to investigate the effect of PSD on the electrical resistivity curves. This work helps to examine the use of Archie's equation for field applications, specifically, for evaluating formations with wide PSDs.

A Study on the Surface Wettability of Clastic Rocks with Potential Application for CO2 Storage Sites

There have been many studies carried out in the past decades attempting to develop strategies for a safe injection of CO2 into storage sites without leakage and contamination of valuable resources. Leakage from these storage sites through capillary seals is one of the long-standing issues, which require a comprehensive assessment prior to CO2 injection. However, surface wettability, which is one of the major parameters controlling the capillary pressure of seals, is a poorly understood parameter, changing as a function of temperature, pressure, surface roughness, etc. The aim of this paper is to provide a deeper insight into the surface wettability of minerals in rocks, especially sandstone and shales, under subsurface conditions for a better assessment of the structural integrity in CO2 storage sites. The results obtained from a series of contact angle measurements under different pressure and temperature conditions indicated that quartz- and feldspar-dominated sandstones are strongly water wet, while kaolinite-dominated shales have a weakly water to intermediate wet system. It is also apparent that the interfacial tension is a function of the pressure and temperature conditions. It appears that the size of pore throats in rocks is the major contributor to capillary threshold pressure and it must be determined very accurately. It is recommended that surface wettability and interfacial tension under reservoir conditions are determined a priori to ensure that the seal integrity analysis is as concise as possible.

Effective Rheology of Two-Phase Flow in a Capillary Fiber Bundle Model

We investigate the effective rheology of two-phase flow in a bundle of parallel capillary tubes carrying two immiscible fluids under an external pressure drop. The diameter of each tube varies along its length and the corresponding capillary threshold pressures are considered to be distributed randomly according to a uniform probability distribution. We demonstrate through analytical calculations that a transition from a linear Darcy regime to a non-linear behavior occurs while decreasing the pressure drop $\Delta P$, where the total flow rate $\langle Q \rangle$ varies with $\Delta P$ with an exponent $2$. This exponent for the non-linear regime changes when a lower cut-off $P_m$ is introduced in the threshold distribution. We demonstrate analytically that, in the limit where $\Delta P$ approaches $P_m$, the flow rate scales as $\langle Q \rangle \sim (|\Delta P|-P_m)^{3/2}$. We have also provided some numerical results in support to our analytical findings.

Application of neural networks in multiphase flow through porous media: Predicting capillary pressure and relative permeability curves

Artificial Neural Networks (ANN) are trained to simulate two-phase capillary pressure and relative permeability data in bundles of capillary tubes with non-uniform arbitrary wettability conditions and cross-sectional shapes of different irregular convex polygons. All polygons with variable number of corners are randomly generated for a given range of inscribed radii, shape, and elongation factors. To generate the data for the training of ANNs, the minimization of Helmholtz free energy and Mayer-Stowe-Princen (MS-P) method are combined to find thermodynamically consistent threshold capillary pressures for two-phase flow. These capillary pressures are then used to determine the sequence of displacements in different capillary tubes. We calculate saturations and phase conductance at each quasi steady-state condition where no more displacements can be done for a given capillary pressure. The generated two-phase capillary pressure and relative permeability curves are then used for the training of ANNs. We test different designs of ANNs to find the optimal workflow for the training and predicting of petrophysical properties related to multiphase flow. In this work, we present the results of two different neural network structures. In the first structure, we use ANN to predict threshold capillary pressures of different capillary tubes during a drainage process (i.e., oil-to-water displacements). In the second structure, we predict capillary pressure and relative permeability curves for an arbitrary bundle of capillary tubes. The first structure of ANNs simulates a fixed property for a given capillary tube, whereas the second structure simulates time-series data format (i.e., for a given bundle of capillary tubes calculated properties vary with saturation). To do so, we have generated multi-phase flow properties for two large datasets consisting of 40,000 and 60,000 capillary tubes each. High-quality training datasets are critical in the training of high-fidelity ANN models. These models can then learn the impact of a wide variety of pore geometries (i.e., shape factors and elongations). Additionally, feature selection and preprocessing of the input data could significantly impact ANN's predictions. The multi-layer perceptron (MLP) neural network with three hidden layers with four outputs is adequate for predicting capillary pressure and relative permeability curves during drainage. This model is approximately an order of magnitude faster than conventional direct calculations using a desktop computer with four cores CPU. Such improvement in the speed of calculations becomes significant when dealing with larger models, more dimensions, and/or introducing pore connectivity in 3D.

Surfactant Prefloods During Carbon Dioxide Foam Injection for Integrated Enhanced Oil Recovery in Fractured Oil-Wet Carbonates

Summary An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

A further verification of FZI* and PSRTI: Newly developed petrophysical rock typing indices

Despite the differences between petrophysical static (PSRTs) and dynamic rock types (PDRTs), previous indices were unable to distinguish between them. FZI-Star (FZI*) and PSRTI are recently developed petrophysical dynamic and static rock typing indices, respectively. Considering the importance of rock typing in reservoir characterization and the need for reliable and user-friendly techniques, in this study we attempt to further verify the performance of FZI* and PSRTI by comparing them with FZI, Winland r35, and MFZI using data belonging to a heterogeneous carbonate reservoir from the Asmari Formation. The experimental data set includes 10 primary drainage mercury injection, 29 water-oil, and 45 gas-oil capillary pressure tests for PSRTs prediction in conjunction with 52 water-oil and 51 gas-oil relative permeability data for PDRTs. Moreover, we investigated the correlation between various indices and several petrophysical attributes. We defined these attributes as the integrals of mercury injection capillary pressure, mercury injection threshold capillary pressure, measured r35, capillary pressure, and relative permeability curves along with residual saturations. The results showed that our indices are able to successfully identify static and dynamic rock units with higher accuracy than other indices. Among the other existing methods, Winland r35 was the only one that showed an acceptable outcome; while, FZI, and MFZI underperformed in identifying the existing rock types. Using the experimental data we also propose the empirical equations that can be used to model capillary pressure and relative permeability characteristics of rocks.

Determination of Effective Parameters of Gas Injection in Naturally Fractured Reservoirs by Combination of Reservoir Simulation and Design of Experiment Techniques

Screening analysis is a useful guideline which helps us with proper field selection for different enhanced oil recovery processes. In this work, reservoir simulation is combined with experimental design to estimate main effects and possible interactions of reservoir rock and fluid properties on performance of different gas injection processes in naturally fractured reservoirs (NFRs). Studied parameters include reservoir thickness (h), oil viscosity μo), pore size distribution (λ), horizontal permeability (Kh), storage capacity (ω), reservoir dip, critical water saturation (Swc) and threshold capillary pressure (pct). The recovery factors of different simulation designs are analyzed by use of fractional factorial design (FFD) approach. Finally, the statistical significance of results are evaluated by hypothesis testing and ANOVA, and presented by Pareto and tornado plots. Main effect analysis showed that effective parameters are ordered with respect to their importance as follows: For Methane and nitrogen injection: Kh, dip, Swc, ω, h, μo and λ; threshold capillary pressure showed a minor effect on recovery factor. For Carbon dioxide injection: μo, dip, Swc, ω, h and Kh; Pore size distribution (λ) and threshold pressure were not shown to be statistically significant in this process. Likeness of main effects and parameter interactions for methane and nitrogen injection prove the similarity of dominant mechanisms and characteristics of these processes compared to CO2 injection which seems almost different.

Modeling the Effect of Fibre Surface Morphology on Liquid Water Transport in Polymer Electrolyte Membrane Fuel Cell Gas Diffusion Layers

In this work, we present a novel methodology for incorporating the effect of fibre surface morphology on liquid water transport in polymer electrolyte membrane fuel cell gas diffusion layers (GDLs). Roughness features presented on the surface of the fibre are analysed using atomic force microscopy and are found to significantly impact the capillary pressure of liquid water pathways propagating through the GDL. A threshold capillary pressure was defined as the largest capillary pressure exhibited by the liquid water phase during the invasion of the throat. The threshold capillary pressures observed in the presence of roughness features are significantly greater than those in the absence of roughness features. Two-dimensional circumferential roughness models in cylindrical and converging-diverging throats are established, and an interfacial meniscus advancing algorithm is presented to determine the resulting threshold capillary pressures required for liquid water penetration. Revised Young–Laplace equations, which are particularly useful for pore network modeling, are suggested for calculating threshold capillary pressures that account for the effect of the roughness of throats with intrinsic contact angles greater than $$90^{\circ }$$ .

Toward direct pore-scale modeling of three-phase displacements

Abstract A stable spreading film between water and gas can extract a significant amount of bypassed non-aqueous phase liquid (NAPL) through immiscible three-phase gas/water injection cycles. In this study, the pore-scale displacement mechanisms by which NAPL is mobilized are incorporated into a three-dimensional pore morphology-based model under water-wet and capillary equilibrium conditions. The approach is pixel-based and the sequence of invasions is determined by the fluids’ connectivity and the threshold capillary pressure of the advancing interfaces. In addition to the determination of three-phase spatial saturation profiles, residuals, and capillary pressure curves, dynamic finite element simulations are utilized to predict the effective permeabilities of the rock microtomographic images as reasonable representations of the geological formations under study. All the influential features during immiscible fluid flow in pore-level domains including wetting and spreading films, saturation hysteresis, capillary trapping, connectivity, and interface development strategies are taken into account. The capabilities of the model are demonstrated by the successful prediction of saturation functions for Berea sandstone and the accurate reconstruction of three-phase fluid occupancies through a micromodel.