Capillary Pressure Saturation Research Articles

Semi-analytical Model to Predict Dynamic Capillary Pressure–Saturation Relationship for Flows in Heterogeneous Porous Media

The capillary pressure defines pressure difference between non-wetting and wetting fluids. The capillary pressure is part of the flow governing equations, and its definition can have a profound impact on the nature of fluids displacement in a multiphase flow environment. Conventionally, capillary pressure–saturation relationships are determined under equilibrium conditions which signify that all the fluid–fluid interfaces that exist at the pore scale maintain a static configuration at a certain instant in time. However, there exist experimental and numerical evidences that state that the dynamic nature of fluid flows indeed plays a prominent role in defining the trends of the capillary pressure–saturation relationships. In this paper, we develop a first of a kind semi-analytical model to predict the capillary pressure–saturation curves during drainage displacement by integrating the dynamics of fluid flow based on fundamental laws of fluid mechanics. The proposed semi-analytical model can potentially be incorporated into existing multiphase flow simulators to rapidly compute the capillary pressure at various saturations of the flow medium under dynamic flow conditions. The presented semi-analytical model has been validated against experimental and numerical data sets available in the literature at various flow conditions and considering different sets of fluid properties. We noticed a satisfactory match of the results predicted by the proposed semi-analytical model against the literature data. After performing a holistic sensitivity analysis, we notice that the properties of the porous medium, and the fluid–solid interactions play a significant role in defining the trends of the capillary pressure–saturation curves.

Study on dryout heat flux of axial stratified debris bed under top-flooding

The coolability of the debris bed with a simulant of solidified corium is experimentally studied, focusing on the effects of the structure of the axial stratified debris bed on the dryout heat flux (DHF). DHF was obtained for the four structures with different particle sizes for the axial stratified debris bed under top flooding. The experimental results show that the dryout position of the axial stratified debris bed is formed at the stratified interface indicated by the temperature rise, and the DHF of the axial stratified bed is much lower than that of the homogeneous bed packed with the upper small particles. To predict the dryout heat flux of the stratified debris beds, by considering the properties of the mixed area, a one-dimensional dryout heat flux model of the porous medium is derived from a water and vapor momentum equation for porous medium, two-phase permeability modifications, interfacial drag, and the correlation between capillary pressure and liquid saturation and verified with the experimental data. The modified model can give reasonable results under different structures.

Comparative analysis of hydrogen, methane and nitrogen relative permeability: Implications for Underground Hydrogen Storage

Underground Hydrogen Storage (UHS) is an emerging technology which aims to store terawatt-scale energy in the subsurface to alleviate daily and seasonal fluctuations in the ever-increasing renewable energy market. Depleted gas reservoirs and aquifers will be the main targets of storage which requires an understanding of the interaction between formation or cushion gas with native brine. A comprehensive comparison of the petrophysical and two-phase flow properties of the hydrogen-water, methane-water and nitrogen-water systems at in-situ conditions is the focus of our work. We conduct steady-state relative permeability experiments at 2.13 MPa and 298 K using identical capillary numbers of Nc=2.92×10−7 for all three systems. The saturation and in-situ contact angles are determined with segmentation of 3D micro-CT images. The contact angle of each system is almost identical at the irreducible water saturation, Swi, 44°, 46°, 45°, respectively, as is the interfacial tension of 72.0, 71.5 and 71mN/m, respectively. The capillary pressure-saturation relationships for each system have a maximum difference of 3.8 % which leads to approximately equivalent relative permeability in the Bentheimer sandstone core. The end-point relative permeabilities are krg0=0.049, krg0=0.045 and krg0=0.062 at irreducible water saturations of Swi=0.24, Swi=0.25 and Swi=0.23, respectively. All three gases demonstrate equivalent flow properties which indicates that both nitrogen and methane are suitable analogue gases for laboratory multiphase flow experiments and cushion gas to improve safety and the economics of commercial UHS projects. The results enable history matched depleted gas reservoir performance to be used as a guide for UHS.

Image-based pore-scale modelling of the effect of wettability on breakthrough capillary pressure in gas diffusion layers

Wettability design is of crucial importance for the optimization of multiphase flow behaviour in gas diffusion layers (GDLs) in fuel cells. The accumulation of electrochemically-generated water in the GDLs will impact fuel cell performance. Hence, it is necessary to understand multiphase displacement to design optimal pore structures and wettability to allow the rapid flow of gases and water in GDLs over a wide saturation range. This work uses high-resolution in situ three-dimensional X-ray imaging combined with a pore network model to investigate the breakthrough capillary pressure and water saturation in GDLs manufactured with different mass fractions of polytetrafluoroethylene coating: 5, 20, 40, and 60%, making them more hydrophobic. We first demonstrate that the pore network extraction method provides representative networks for the fibrous porous media examined. Then, using a pore-network flow model we simulate water invasion into initially gas-filled fibrous media, and analyze the effect of wettability on breakthrough capillary pressure and water saturation. With an appropriate pore-scale characterization of wettability, a pore network model can match experimental results and predict displacement behaviour.

New insights into pore fractal dimension from mercury injection capillary pressure in tight sandstone

Mercury injection capillary pressure (MICP) has been widely used for pore fractal dimension determination and thus leads to a variety of calculation models with different results. Here, taking the tight sandstone gas reservoir of Shaximiao Formation in Jinhua-Zhongtaishan area, central Sichuan Basin as the object, the theory, method and application of pore fractal dimension determination from MICP are explored. Based on Yu-Xia model and Washburn equation, rigorous analytical expressions on fractal dimension, capillary pressure and mercury saturation are deduced. After pre-processing including validation, consistency correction and shape-preserving interpolation, the fractal turning point is located with the local maximum of the front-back moving variance ratio of mercury saturation, and then the global, macropore and micropore fractal dimensions are determined respectively by nonlinear fitting. As suggested by the data processing results of the 39 MICP samples, there is no significant direct correlation between pore fractal dimensions and petrophysical properties represented by permeability. However, the combination of fractal model related parameters, especially global fractal dimension and entry pressure, can identify effectively reservoir quality ranks. Meanwhile, for gas layers with relatively high permeability, larger global fractal dimensions may imply roughly more favorable pore structure and better reservoir quality, while the total quality of the relatively low-permeability gas layers is poor and nearly independent of the fractal dimensions. The representative MICP-based pore fractal models, He-Hua and Shen-Li, are critically reviewed. The theoretical simplification and calculative approximate of these two models lead to some degree of error in pore fractal dimension determination, despite their slight correlation in the fitting results with those of the present model. This study may improve the understanding of the pore fractal dimension determined from MICP and provide reference for pore structure evaluation, reservoir quality classification and capillary pressure modeling.

Prediction of two-phase flow properties for digital sandstones using 3D convolutional neural networks

Multiphase fluid flow within porous media is of great importance in a wide range of environmental and industrial fields, such as CO2 sequestration, geothermal systems, fuel cells, enhanced oil recovery, and groundwater remediation. Pore-scale modeling is a promising tool to estimate macroscopic multiphase flow properties from micro-scale images of porous materials; however, it is a complex, time-consuming procedure and would be highly resource-intensive in the case of direct numerical simulation. We present a framework that consists of (1) extraction of sub-samples from rock images, (2) computation of relative permeability and capillary pressure from two-phase pore network modeling with respect to their contact angle and interfacial tensions, (3) training a convolutional neural network (CNN), and (4) validation with unseen datasets and parameters. 500 sub-samples of grayscale and binary types are extracted from images of 12 different sandstones. Relative permeability, capillary pressure, and residual saturation of binary sub-samples are computed from two-phase fluid flow simulation in their representative pore network models The proposed CNN model is trained with grayscale images, eliminating the need for image processing. The results demonstrate a good agreement between CNN predictions and simulation results, and the computational time was reduced by several orders of magnitude.

Forced imbibition and uncertainty modeling using the morphological method

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.

A lattice Boltzmann exploration of two-phase displacement in 2D porous media under various pressure boundary conditions

While experimental designs developed in recent decades have contributed to research on dynamic nonequilibrium effects in transient two-phase flow in porous media, this problem has been seldom investigated using direct numerical simulation (DNS). Only a few studies have sought to numerically solve Navier–Stokes equations with level-set (LS) or volume-of-fluid (VoF) methods, each of which has constraints in terms of meniscus dynamics for various flow velocities in the control volume (CV) domain. The Shan–Chen multiphase multicomponent lattice Boltzmann method (SC-LBM) has a fundamental mechanism to separate immiscible fluid phases in the density domain without these limitations. Therefore, this study applied it to explore two-phase displacement in a single representative elementary volume (REV) of two-dimensional (2D) porous media. As a continuation of a previous investigation into one-step inflow/outflow in 2D porous media, this work seeks to identify dynamic nonequilibrium effects on capillary pressure–saturation relationship ( P c – S ) for quasi-steady-state flow and multistep inflow/outflow under various pressure boundary conditions. The simulation outcomes show that P c , S and specific interfacial area ( a nw ) had multistep-wise dynamic effects corresponding to the multistep-wise pressure boundary conditions. With finer adjustments to the increase in pressure over more steps, dynamic nonequilibrium effects were significantly alleviated and even finally disappeared to achieve quasi-steady-state inflow/outflow conditions. Furthermore, triangular wave-formed pressure boundary conditions were applied in different periods to investigate dynamic nonequilibrium effects for hysteretical P c – S . The results showed overshoot and undershoot of P c to S in loops of the nonequilibrium hysteresis. In addition, the flow regimes of multistep-wise dynamic effects were analyzed in terms of Reynolds and capillary numbers ( Re and Ca ). The analysis of REV-scale flow regimes showed higher Re (1 < Re < 10) for more significant dynamic nonequilibrium effects. This indicates that inertia is critical for transient two-phase flow in porous media under dynamic nonequilibrium conditions.

A Closed-Form Equation for Capillary Pressure in Porous Media for All Wettabilities

A saturation–capillary pressure relationship is proposed that is applicable for all wettabilities, including mixed-wet and oil-wet or hydrophobic media. This formulation is more flexible than existing correlations that only match water-wet data, while also allowing saturation to be written as a closed-form function of capillary pressure: we can determine capillary pressure explicitly from saturation, and vice versa. We propose Pc=A+Btanπ2-πSeCfor0≤Se≤1,\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$P_{{\ ext{c}}} = A + B\ an \\left( {\\frac{\\pi }{2} - \\pi S_{e}^{C} } \\right)\\,{\ ext{for}}\\,0 \\le S_{{\ ext{e}}} \\le 1,$$\\end{document}where S_{{text{e}}} is the normalized saturation. A indicates the wettability: A>0 is a water-wet medium, A<0 is hydrophobic while small A suggests mixed wettability. B represents the average curvature and pore-size distribution which can be much lower in mixed-wet compared to water-wet media with the same pore structure if the menisci are approximately minimal surfaces. C is an exponent that controls the inflection point in the capillary pressure and the asymptotic behaviour near end points. We match the model accurately to 29 datasets in the literature for water-wet, mixed-wet and hydrophobic media, including rocks, soils, bead and sand packs and fibrous materials with over four orders of magnitude difference in permeability and porosities from 20% to nearly 90%. We apply Leverett J-function scaling to make the expression for capillary pressure dimensionless and discuss the behaviour of analytical solutions for spontaneous imbibition.

Simultaneous interpretation of SCAL data with different degrees of freedom and uncertainty analysis

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.

Estimation of Initial Oil in Place for Buzurgan Oil Field by Using Volumetric Method and Reservoir Simulation Method

The estimation of the initial oil in place is a crucial topic in the period of exploration, appraisal, and development of the reservoir. In the current work, two conventional methods were used to determine the Initial Oil in Place. These two methods are a volumetric method and a reservoir simulation method. Moreover, each method requires a type of data whereet al the volumetric method depends on geological, core, well log and petrophysical properties data while the reservoir simulation method also needs capillary pressure versus water saturation, fluid production and static pressure data for all active wells at the Mishrif reservoir. The petrophysical properties for the studied reservoir is calculated using neural network technique from 13 cored and logged wells. The results showed that the reservoir simulation method gave a value of Initial Oil in Place that agrees and close to the value of Initial Oil in Place obtained from the volumetric method with a percentage different around 2%. However, the estimation of Initial Oil in Place by reservoir simulation method offered accurate results during good history matching with observed data as well as making appropriate adjusting for Pc vs. Sw values for the whole reservoir from October 1976 until December2020. MB21 unit own most Initial Oil in Place equal to 525*106 SM3 while MB12 has lowest IOIP equal to 2*106 SM3. Finally, the calculation of Initial Oil in Place by both volumetric and simulation methods presented good results while comparing with previous study at 2013 with discovered different around 1.5% and 0.6% respectively.

A Thermal-Hydraulic-Gas-Mechanical Coupling Model on Permeability Enhancement in Heterogeneous Shale Volume Fracturing

Heat treatment on shale reservoirs can promote the development of secondary fractures in a matrix on the basis of hydraulic fracturing, forming multi-scale gas–water seepage channels and strengthening the gas desorption. Experimental evidence shows that heat treatment can enhance gas recovery in the same mining life. Heat treatment on a shale gas reservoir is a multi-physical and multi-phase coupling process. However, how the thermal stimulation interacts with nonlinear two-phase flow in heterogeneous shale volume fracturing has not been clear. In this paper, a fully coupled THGM model for heating-enhanced shale-gas recovery in heterogeneous shale reservoirs is proposed. First, the governing equations are formulated for the shale-reservoir deformation involving both gas adsorption and thermal expansion, the permeability evolution model for the cracking process of fractured shale, the gas–water two-phase continuity equation considering the effects of gas solubility and the heat transfer equation for heat conduction and convection. The interactions among stress, temperature and seepage in a heterogeneous shale reservoir were studied. Secondly, a test on shale permeability after 50 °C temperature treatment was conducted. The evolution of temperature, capillary pressure, water and gas saturation and the permeability of shale during the heat treatment of the reservoir were numerically analyzed. Finally, the gas production from a shale gas reservoir was numerically simulated with this THGM model. The numerical results indicated that the thermal-induced fracturing, gas desorption and separation from water make predominant contributions to the evolution of permeability. The heat treatment can enhance cumulative gas production by 58.7% after 27.4 years of heat injection through promoting gas desorption and matrix diffusion.

Effects of Enzymatically Induced Carbonate Precipitation on Capillary Pressure–Saturation Relations

Leakage mitigation methods are an important part of reservoir engineering and subsurface fluid storage, in particular. In the context of multi-phase systems of subsurface storage, e.g., subsurface CO2 storage, a reduction in the intrinsic permeability is not the only parameter to influence the potential flow or leakage; multi-phase flow parameters, such as relative permeability and capillary pressure, are key parameters that are likely to be influenced by pore-space reduction due to leakage mitigation methods, such as induced precipitation. In this study, we investigate the effects of enzymatically induced carbonate precipitation on capillary pressure–saturation relations as the first step in accounting for the effects of induced precipitation on multi-phase flow parameters. This is, to our knowledge, the first exploration of the effect of enzymatically induced carbonate precipitation on capillary pressure–saturation relations thus far. First, pore-scale resolved microfluidic experiments in 2D glass cells and 3D sintered glass-bead columns were conducted, and the change in the pore geometry was observed by light microscopy and micro X-ray computed tomography, respectively. Second, the effects of the geometric change on the capillary pressure–saturation curves were evaluated by numerical drainage experiments using pore-network modeling on the pore networks extracted from the observed geometries. Finally, parameters of both the Brooks–Corey and Van Genuchten relations were fitted to the capillary pressure–saturation curves determined by pore-network modeling and compared with the reduction in porosity as an average measure of the pore geometry’s change due to induced precipitation. The capillary pressures increased with increasing precipitation and reduced porosity. For the 2D setups, the change in the parameters of the capillary pressure–saturation relation was parameterized. However, for more realistic initial geometries of the 3D samples, while the general patterns of increasing capillary pressure may be observed, such a parameterization was not possible using only porosity or porosity reduction, likely due to the much higher variability in the pore-scale distribution of the precipitates between the experiments. Likely, additional parameters other than porosity will need to be considered to accurately describe the effects of induced carbonate precipitation on the capillary pressure–saturation relation of porous media.

Numerical modeling of frequency-dependent velocity and attenuation in a fractured-porous rock saturated with two immiscible fluids

The dispersion and attenuation of seismic-wave propagation induced by ‘squirt flow’ effects in hydrocarbon-saturated reservoirs are significantly affected by their rock properties and fluid content. In this study, we analyse the frequency-dependent velocity, attenuation, and seismic responses when fractured porous rock is saturated with two immiscible fluids. First, when considering reservoir wettability, we calculate the effective fluid viscosity using a stable parameter, the capillary pressure, and a lattice Boltzmann model (LBM)-based relative permeability equation, which is a function of the saturation and viscosity ratio of the immiscible two-phase fluid. Then, we explore the frequency-dependent effects of fractured porous rocks saturated with two immiscible fluids under different cases of viscosity ratios and capillary pressure parameters by employing the Chapman model from the dynamic equivalent-medium theory. Then, we use a four-layer model to analyse the frequency-dependent seismic responses. The results show that the characteristics of frequency-dependent velocity and attenuation are both affected by the wettability, capillary pressure parameter, saturation, and viscosity ratio. The frequency-dependent features are greatly influenced by the capillary pressure parameter and viscosity ratio. For a larger viscosity ratio and lower capillary parameter, a dispersive effect can occur in the seismic frequency band. This indicates that the velocity dispersion anomalies are sensitive to wettability, capillary pressure parameter and viscosity ratio and should not be neglected. Synthetic seismic records demonstrate that the seismic reflection signatures, such as the waveform, amplitude, and reflective travel time, at the interfaces for saturated reservoirs are significantly affected by wettability and saturation. The numerical modeling helps to improve the wave propagation in rocks saturated by two immiscible fluids.

Modeling drainage in porous media considering locally variable contact angle based on pore morphology method

• A new pore morphology method, Lvca–PMM, is proposed. • Lvca–PMM considers locally variable contact angles. • Lvca–PMM can produce the capillary pressure–saturation curves. • Contact angles and fluid distributions can be well simulated by Lvca–PMM. • Lvca–PMM presents better results than the method by Schulz et al (2014). The pore morphology method (PMM) has been widely applied to simulate the quasi–static drainage process of porous media, which requires less computational time and computer memory compared to other two–phase flow simulation methods. However, most of the existing pore morphology simulations were restricted to totally wetting systems (i.e., contact angle is equal to zero). Here, we propose a new pore morphology method (Lvca–PMM) enhanced by considering locally variable contact angles, which now enables a reproduction of the primary drainage process for porous media under different wettability conditions featuring the full range of contact angle for wetting phase for various spatial distribution. A series of simulations are performed by using the Lvca–PMM to a porous medium under different uniform and mixed wettability conditions. The proposed Lvca–PMM presents a better result compared to the method by Schulz et al. (2014) for different wettability conditions. The capillary pressure–saturation relations as well as the pore–scale fluid distributions can be well captured by the proposed Lvca-PMM.

Finite Element Model to Simulate Two-Phase Fluid Flow in Naturally Fractured Oil Reservoirs: Part I.

Naturally fractured reservoirs host more than 20% of the world’s total oil and gas reserves. To produce from such reservoirs efficiently, a good understanding of the reservoir behavior at various conditions is essential. This allows us to predict the reservoir performance in advance and assess its economic feasibility. However, the production from such reservoirs is challenging due to (a) uncertainty associated with the fracture map, (b) complex physics phenomena of fluid and rock interaction, and (c) lack of comprehensive knowledge of the extent, orientation, and permeability sensitivity of the fracture network. This paper addresses the abovementioned challenges by presenting a three-dimenisonal (3-D) two-phase fluid flow model in a poroelastic environment. The model is based on a hybrid methodology by combining single continuum and discrete fracture network approaches. Also, the capillary pressure effect, saturation, and relative permeability variations are considered. A mathematical formulation for three-dimensional, two immiscible fluid flows including rock deformation for the fracture network and the rock matrix is presented. A standard Galerkin-based finite element method is applied to discretize the poroelastic governing equations in space and time. The characteristic Galerkin discretization method is used to stabilize the solution of the convection equation in a finite element approach. The 3-D model is validated against IMEX commercial software and finite element package to test its robustness. The results show that the developed model has the ability to predict the two-phase flow behavior precisely, which can be used to assess the production performance of naturally fractured reservoirs. Numerical results of fluid flow profiles for single and multiple fractures with different orientations that match experimental oil drainage tests and field case studies are presented that proves the reliability of the developed multiphase flow model. Results of simulated well production data show an excellent match with the field production data.

Application of benchtop humidity and temperature chamber in the measurement of water vapor sorption in US shales from Mancos, Marcellus, Eagle Ford and Wolfcamp formations

A benchtop humidity and temperature chamber was used to assess water vapor sorption in four US shale samples at 90 °C. Water sorption isotherms were measured at relative humidity ranging from 10 to 99% and temperature of 90 °C. Shale fractal properties were then evaluated, and capillary pressure (ranging from 1.70 to 386 MPa) was obtained using Kelvin relationship. The results show that Mancos shale, from the US, adsorbed more absorbed water due to its high clay concentration and low TOC. However, Wolfcamp shale, from the US, has the lowest TOC and clay concentration, adsorbing the lowest amount of water. There is little hysteresis between adsorption and desorption isotherms explaining water retention phenomenon in some shales. The obtained fractal dimension values ranged between 2.45 and 2.76 and average of 2.56 indicating irregular pore surface and complex pore structure. All shale sample's capillary curves were fitted to Brooks & Corey and van Genuchten models with nonlinear regression. The fitting coefficient, R2, which represents the proportion of variance for Brooks & Corey fits ranged from 0.90 to 0.97 for imbibition and 0.85 to 0.98 for drainage, while R2 for the van Genuchten model ranged from 0.94 to 0.99 for both imbibition and drainage. Thus, the proposed method can be used to measure capillary pressure–saturation relationships in gas shales.

Analysis and Application of Capillary Pressure Data

The article proposes a method for determining the water saturation of oil and gas reservoirs based on the use of typical capillary pressure curves. There is a relationship between capillary pressure and water saturation, which consists in the fact that residual water is retained in the pore, hydrocarbon-saturated space of the reservoir due to capillary forces. Based on the results of a laboratory study of 75 core samples, typical capillary pressure curves were constructed. Using these curves, it is possible to determine such reservoir parameters as: residual water saturation, water saturation at a given distance from the OWC and others. Knowledge of these parameters will improve the control and regulation of the development of oil and gas fields.

A sensitivity analysis of factors affecting in geologic CO2 storage in the Ordos Basin and its contribution to carbon neutrality

To accelerate the achievement of China’s carbon neutrality goal and to study the factors affecting the geologic CO2 storage in the Ordos Basin, China’s National Key R&D Programs propose to select the Chang 6 oil reservoir of the Yanchang Formation in the Ordos Basin as the target reservoir to conduct the geologic carbon capture and storage (CCS) of 100000 t per year. By applying the basic theories of disciplines such as seepage mechanics, multiphase fluid mechanics, and computational fluid mechanics and quantifying the amounts of CO2 captured in gas and dissolved forms, this study investigated the effects of seven factors that influence the CO2 storage capacity of reservoirs, namely reservoir porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability, capillary pressure, and residual gas saturation. The results show that the sensitivity of the factors affecting the gas capture capacity of CO2 decreases in the order of formation stress, temperature, residual gas saturation, horizontal permeability, and porosity. Meanwhile, the sensitivity of the factors affecting the dissolution capture capacity of CO2 decreases in the order of formation stress, residual gas saturation, temperature, horizontal permeability, and porosity. The sensitivity of the influencing factors can serve as the basis for carrying out a reasonable assessment of sites for future CO2 storage areas and for optimizing the design of existing CO2 storage areas. The sensitivity analysis of the influencing factors will provide basic data and technical support for implementing geologic CO2 storage and will assist in improving geologic CO2 storage technologies to achieve China’s carbon neutralization goal.©2022 China Geology Editorial Office.

PORE-SCALE INVESTIGATION OF WETTING STRENGTH ON CAPILLARY PRESSURE HYSTERESIS IN A REALISTIC POROUS MEDIA

Capillary hysteresis is known as a characteristic of a real porous structure that strongly affects the micromechanism of immiscible fluids displacement so that its understanding provides a better insight from pore-scale studies. This study aims to investigate capillary hysteresis and characterize wetting strength on the capillary pressure-saturation curve using lattice Boltzmann method. After benchmark tests, a comprehensive procedure for recording capillary hysteresis at the pore-scale simulations is presented. Studies have been done in three wetting categories, including nearly neutral wet, moderately wet, and strongly wet. The interesting point is the capillary pressure bump phenomenon in the forced drainage process, so that this model has been able to record it well. Since the capillary pressure plays a resistive role for the displacement of immiscible fluids in the drainage process, the wetting condition controls the flow pattern intensely. Overall, results show that increasing the wetting strength will intensify this phenomenon, despite imbibition and drainage curves shifting toward higher capillary pressures. Indeed, the reason for this is an excessive increase in capillary pressure in some pores. Other interpretations of the results show that increasing the wetting strength will allow more wetting fluid to be trapped in the drainage process, which is a sign of the capillary trapping phenomenon.