Capillary Pressure Curves Research Articles

Reservoir rock typing and electrofacies characterization by integrating petrophysical properties and core data in the Bangestan reservoir of the Gachsaran oilfield, the Zagros basin, Iran

The super-giant Gachsaran oilfield is situated in the Dezful Embayment of the Zagros basin. The main goal of this study is to characterize the reservoir rock types by integrating the available geological and petrophysical studies in the Bangestan reservoir along with adopting a way to figure out the optimal number of electrofacies codes. At the first step, the types of porosity and geological microfacies were studied by using 163 thin sections from the core samples. The microscopic studies revealed that fractures and intraparticle interstices are the most common porosities types. Also, they resulted in the identification of 4 microfacies in the Bangestan reservoir. In a complementary study, the Velocity-Deviation Log (VDL) was employed to determine the dominant pore types. By comparison of the VDL values and thin section studies’ results, it was deduced that high micro-porosities along with hairline fractures are the predominant pore types of the Bangestan reservoir. At the second step, the optimal number of reservoir rock types (RRT) was determined by using the concept of hydraulic flow units. Thus, six flow units were distinguished by utilizing the Flow Zone Indicator (FZI) method in which the reservoir properties were improved from RRT-1 toward RRT-6. In the third step, the data clustering analysis, known as the electrofacies analysis, was employed to identify the accurate petrophysical rock types based on the meaningful segregation of capillary pressure curves within each electrofacies code and then propagated in non-cored intervals and boreholes. In this research, an optimal number of 7 electrofacies were identified by employing the petrophysical curves including effective porosity (PHIE), bulk density (RHOB), sonic (DT), and water saturation (SWE), along with considering the number of reservoir rock types and the defined geological microfacies, as well as the relations of the available capillary pressure data within different electrofacies codes. The validity of the proposed electrofacies was scrutinized through petrophysical results including shale volume, water saturation, and effective porosity. In the end, the electrofacies codes were compared to the defined geological microfacies. Finally, this study shows that the correlation of capillary pressure data and electrofacies codes can be resulted in figuring out the optimal number of electrofacies codes. In addition, by trying to honor the link between geological microfacies, capillary pressure, and petrophysical curves, the constructed electrofacies model, as a suitable practical integrated rock typing method, can be the foundation of property modeling, guide the spatial distribution of reservoir properties in the 3D model, aids to model the dynamics of fluid flow more realistically in reservoir simulation phase, and ultimately be beneficial for further development and production decisions in the Bangestan reservoir of the Gachsaran oilfield.

An improved rock typing method for tight sandstone based on new rock typing indexes and the weighted fuzzy kNN algorithm

Petrophysical rock typing is a very important problem in flow unit interpretation and reservoir characterization. Unlike the sandstone, the presence of numerous nanopores in tight sandstone can cause strong gas and liquid non-linear flow. And this makes the traditional rock typing indexes derived from Darcy'law unsuitable for tight sandstone. In this paper, new rock typing indexes, including the Darcy index (Fi), the gas non-Darcy index (Kc) and the liquid non-Darcy index (Sr), have been proposed to describe the non-linear flow characteristics in tight sandstone. In addition, the limit pore ranges for gas and liquid non-Darcy flow have been determined based on these indexes. Then the weighted fuzzy kNN algorithm, which can consider the weight differences between different rock typing indexes, is combined with three indexes to improve the accuracy of rock typing. In order to test the rock typing indexes and the weighted fuzzy kNN algorithm, the tight sandstone dataset in Upper Triassic Yanchang Formation, Ordos Basin, NW China has been constructed with RES (representative element surface) random pore network and experiment data. The results show that the new rock typing indexes and the weighted fuzzy kNN algorithm have better performance in typing tight sandstone than the traditional methods. Moreover, 30 mercury injection capillary pressure (MICP) curves measured on highly inhomogeneous tight sandstone samples from the research area have also been used to validate our method. All the results have proved that the proposed new rock typing indexes and weighted fuzzy kNN algorithm can type the tight sandstone very well, and they play a significant role in permeability prediction, reservoir modeling and simulation. • New rock typing indexes have been proposed to describe the non-Darcy flow characteristics in tight sandstone. • The limit pore ranges for gas and liquid non-Darcy flow have been determined based on the new indexes. • The weighted fuzzy kNN algorithm is combined with three indexes to improve the accuracy of rock typing. • The improved method has been proved to have better performance in typing tight sandstone than the traditional methods.

In-situ hydrogen wettability characterisation for underground hydrogen storage

Hydrogen storage in subsurface aquifers or depleted gas reservoirs represents a viable long-term energy storage solution. There is currently a scarcity of subsurface petrophysical data for the hydrogen system. In this work, we determine the wettability and Interfacial Tension (IFT) of the hydrogen-brine-quartz system using captive bubble, pendant drop and in-situ 3D micro-Computed Tomography (CT) methods. Effective contact angles ranged between 29° and 39° for pressures 6.89–20.68 MPa and salinities from distilled water to 5000 ppm NaCl brine. In-situ methods, novel to hydrogen investigations, confirmed the water-wet system with the mean of the macroscopic and apparent contact angle distributions being 39.77° and 59.75° respectively. IFT decreased with increasing pressure in distilled water from 72.45 mN/m at 6.89 MPa to 69.43 mN/m at 20.68 MPa. No correlation was found between IFT and salinity for the 1000 ppm and 5000 ppm brines. Novel insights into hydrogen wetting in multiphase environments allow accurate predictions of relative permeability and capillary pressure curves for large scale simulations. • Comprehensive characterisation of hydrogen-brine-quartz wettability. • Novel investigation of in-situ contact angle for underground hydrogen storage. • Contact angle on smooth rock surface 27–39° and at in situ conditions 39.77–59.75°. • Deficit curvature analysis confirms a water-wet system. • IFT from 72.45 mN/m at 6.89 MPa to 69.43 mN/m at 20.68 MPa.

A two-dimensional study on the impact of pore space connectivity on the immiscible two-phase flow in a water-wet, water–oil system under steady state conditions

Immiscible displacements in porous media are unquestionably of great significance in numerous natural and industrial processes. It has been well established and accepted that in addition to the immiscible fluid properties, the morphology of the porous medium also plays a significant role in the final volumetric throughput of a particular fluid. Topological features of the porous medium have been found to exert a strong influence on the hydrodynamic behaviour of single and two-phase flows as they express a measure of pore space and consequently flow path connectivity and availability. The current study investigates the effect of the pore space connectivity, expressed through the Euler characteristic, on the hydrodynamic behaviour of a water-wet, oil–water two-phase system at steady state. Two-dimensional simulations are conducted in artificially generated porous media with constant diameter circular solid grains using a multi-relaxation time lattice-Boltzmann model. It is shown that topological features of the porous medium can significantly affect the macro-scale capillary pressure and relative permeability curves for drainage and imbibition but in different ways. It is also demonstrated that pore space connectivity has a strong influence on the fluid phase distribution and fragmentation patterns in the porous structure depending on the displacement process.

Developing a saturation-height function for reservoir rock types and comparing the results with the well log-derived water saturation, a case study from the Fahliyan formation, Dorood oilfield, Southwest of Iran

Determining the potential of reservoirs and production zones is very important to reach maximum product performance and decrease hydrocarbon recovery costs. The calculation of the Water Saturation (SW) significantly affects oil-in-place estimations. The Saturation-Height Function (SHF) is operated to predict the saturation in the reservoir for a given height above the free water level. Typical approaches for predicting water saturation as a function of rock properties and height above contact include two types, those based on capillary pressure curve averaging and log-based techniques. The goal of this study is to define an appropriate SHF and SW using the usual functions to delineate production zones using rock typing with an example from the Dorood oilfield in the Persian Gulf. In this study first, the reservoir has been divided into different rock types and water saturation is estimated by different methods in each rock type. The Reservoir Quality Index (RQI) along with Water Saturation profile for representative rock types were used for determining reservoir zones. Accordingly, a formulation was developed to model the behavior of Capillary Pressure (PC) as a characteristic of SW and to determine the Free Water Level (FWL) based on laboratory data. To achieve this goal, the appropriate saturation-height functions and their coefficients were chosen for representative reservoir rock types. The Pc curves are classified based on Discrete Rock Types (DRT) and a proper saturation-height function was assigned for individual rock types. Finally, some of the most common equations for calculating SHF were fitted to the representative Pc curve of each rock type and coefficients of the equation for any rock type were determined by using the MATLAB software in the studied carbonate reservoir. After investigating the results of fitting different SHF, water saturation was calculated using a modified lambda function and compared with the log-derived water saturation. The SHF applied, could be used to estimate saturations of unreachable zones of the field.

Modeling the interplay between water capillary transport and species diffusion in gas diffusion layers of proton exchange fuel cells using a hybrid computational fluid dynamics formulation

Improved modeling of the membrane electrode assembly (MEA) and operation is essential to optimize proton exchange fuel cells (PEFCs). In this work, a hybrid model, which includes a pore network formulation to describe water capillary transport and a continuum formulation to describe gas diffusion, is presented. The model is validated with previous data of carbon-paper gas diffusion layers (GDL), including capillary pressure curve, relative effective diffusivity, g ( s ) , and saturation profile. The model adequately captures the increase of capillary pressure with compression, the nearly cubic dependency of g ( s ) on average saturation, s avg , and the shape of the saturation profile in conditions dominated by capillary fingering (e.g., running PEFC at low temperature). Subsequently, an analysis is presented in terms of the area fraction of water at the inlet and the outlet of the GDL, A w i n and A w o u t , respectively. The results show that gas diffusion is severely hindered when A w i n is exceedingly high (¿80%), a situation that can arise due to the bottleneck created by flooded interfacial gaps. Furthermore, it is found that s avg increases with A w o u t , reducing the GDL effective diffusivity. Overall, the work shows the importance of an appropriate design of MEA porous media and interfaces in PEFCs. • A hybrid model for gas diffusion layers in proton exchange fuel cells is presented. • Pore network & continuum models are used for water transport & gas diffusion, resp. • The model is extensively compared with experimental data, showing good agreement. • The limiting current density dramatically reduces when interfacial flooding occurs. • More isolated evacuation sites toward the channel decrease effective diffusivity.

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 fractal model for obtaining spontaneous imbibition capillary pressure curves based on 2D image analysis of low-permeability sandstone

Spontaneous imbibition (SI) is the principal production mechanism in naturally fractured reservoirs produced by waterflooding and is essential for fluid flow characterization to predict their future performance. As an alternative to the expensive, time-consuming laboratory measurements, 2D images render a different prospect to obtain SI capillary pressure curves, especially for tight reservoirs. This paper introduces a unique approach to infer SI capillary pressure curves from 2D images through integrating image analysis and fractal theory. Using pore-related information obtained from image analysis, we properly represent the pore structure as bundles of tortuous square and triangular tubes with sinusoidally varying radii to imitate cross-sectional variation between pore bodies and throats. Moreover, we simulate the piston-like and snap-off displacement mechanisms to derive an innovative fractal SI capillary pressure model. The developed model considers the contact angle hysteresis caused by surface roughness and heterogeneity of reservoir rocks. The Mayer-Stowe-Princen (MSP) approach is implemented to compute the entry capillary pressure of piston-like displacement. The laboratory-measured porosity and permeability are utilized to determine the model's 3D-related parameters that cannot be inferred from 2D images. The model reliability is verified with the good accuracy of the predicted capillary pressure curves versus laboratory-measured data of five samples from the Liushagang and Huangliu in the South China Sea. Finally, the fundamental parameters influencing the developed SI capillary pressure model are investigated with sensitivity analysis.

Mass transfer of phases in the flow of oil-water-gas mixture on the core scale

The study of three-phase fluid filtration in the pore space is one of the urgent tasks in the development of oil and gas and gas condensate fields. In the study of three-phase flows, semi-empirical methods for calculating relative phase permeabilities (RPP) are used in practice, which do not consider the structure of the pore space and the fundamental equations of hydrodynamics. The paper proposes and substantiates a physical and mathematical model of mass transfer in the filtration flow of an oil-water-gas mixture in a porous medium. The pore space structure model is based on the distribution of pore diameters obtained from capillary pressure curves (CCP). In the core, clusters are identified, consisting of a large channel through which oil, water and gas move in a “beaded” mode; channels of medium diameter filled with water and gas and channels of small radius in which gas moves. A system of equations is presented and solved that determines the distribution of moving volumes and volumetric flows over channels and phases. When determining pressure losses in the system of pore channels, friction losses, local losses, and also losses due to interfacial interaction are taken into account. For the first time, on the basis of a hydrodynamic model, analytical expressions were obtained to determine the RPP for oil, water and gas. The calculation-experimental method is based on three model experiments, the results of which determine the properties of the cluster channels in relation to the separately filtered phases. It is shown that the developed theory and calculation method, in the particular case of an oil-water mixture, coincide with the previously developed theory of two-phase filtration on the core scale.

An Algorithm to Determine the Truncated Weibull Parameters for Distribution of Throats and Pores in Random Network Models

In random network models, sizes for pores and throats are distributed according to a truncated Weibull distribution. As a result, parameters defining the shape of the distribution are critical for the characteristic of the network. In this paper, an algorithm to distribute pores and throats in random network was established to more representatively describe the topology of porous media. First, relations between Weibull parameters and the distribution of dimensionless throat sizes were studied and a series of standard curves were obtained. Then, by analyzing the capillary pressure curve of the core sample, frequency distribution histogram of throat sizes was obtained. All the sizes were transformed to dimensionless numbers ranged from 0 to 1. Curves of the core were compared to the standard curves, and truncated Weibull parameters could be determined according an inverse algorithm. Finally, aspect ratio and average length of throats were adjusted to simultaneously fit the porosity and the capillary pressure curves and the whole network was established. The predicted relative permeability curves were in good agreement with the experimental data of cores, indicating the validity of the algorithm.

DIGITAL CLUSTER MODEL OF PORE SPACE AT FLOW OF THREE-PHASE FLOW IN POROUS MEDIUM

The work is devoted to one of the urgent problems of the oil and gas industry — the study of three-phase filtration. The creation of pore space models is an important stage in the study of the flow of oil and gas mixtures for the subsequent determination of the filtration and reservoir properties of reservoir rocks. The aim of the study is to develop a physical and mathematical model of a porous medium on the scale of a core sample. A digital cluster model for calculating the geometric parameters of the pore space is presented. The structure of the pore space of the cluster model is based on the distribution of pores by diameters obtained from capillary pressure curves (KCD). The core contains clusters consisting of a big channel (B) through which oil, water and gas move in a clear mode, average channels (A) with moving water and gas and small channels (S) with moving gas, as well as bridges between these channels. The division of the pore diameter distribution function into regions related to big, average and small channels is based on empirically determined relationships between the numbers of channels through which fluids move in the pore space in the above combinations. At the same time, the transition from the physical core model to the digital cluster model is carried out with the preservation of porosity, absolute permeability and taking into account the tortuosity of the channels. The dependence of the tortuosity of channels on their diameter is assumed according to a decreasing power law. The model presented in this paper is tested on two examples at different values of effective porosity and the number of intervals of the pore distribution function by diameter. The model has the potential for further development and calculation of the filtration flow of a three-phase mixture (oil, gas and water) on the scale of a core sample.

A Novel Energy Lifting Approach Using J-Function and Flow Zone Indicator for Oil Fields

The X field is located in the southwestern part of block NX89 of Kentan Basin in Libya. This field is produced from Hailan multilayer consolidated sandstone with moderate rock property and a relatively low energy supplying. The reserve of subsurface energy sources is declining with years. Therefore, techniques were combined to achieve the energy optimization and increase hydrocarbon recovery. In order to understand the subsurface formation of the reservoir and facilitate oil production, global hydraulic element technique was used to quantify the reservoir rock types. In addition, stratigraphic modified Lorenz plot was used for reservoir layering. Reservoir heterogeneity was identified using stratigraphic modified Lorenz plot and Dykstra-Parsons coefficient. Leverett J-function was used to average the 13 capillary pressure curves into four main curves to represent the whole reservoir based on flow zone indicator values. Capillary pressure was calculated and plotted with normalized water saturation; a single average curve was defined to represent the rest of the curves. Water saturation was calculated using single and multiple J-functions and compared with the available logs. With multiple J-functions, the matching results were good for both high and low-quality layers, whereas using a single J-function, the match was poor, especially for low FZI layers such as H4c and H6a. Four rock types were identified for this reservoir ranging from medium to good reservoir quality and six different layers were obtained. The reservoir was heterogeneous with a Lorenz coefficient value of approximately 0.72 and a Dykstra-Parsons value of 0.70. All approaches used in this paper were validated and showed improved hydrocarbon recovery factor.

Effects of ultrasonic waves on water imbibition into oil-wet carbonate reservoirs (a case study)

In this study, imbibition tests with and without ultrasonic radiation were performed on limestone samples obtained from the Asmari formation, which is the main Iranian oil reservoirs. The test results have shown a significant increase in the oil recovery with ultrasonic radiation. Reducing the interfacial tension (IFT) and thus reducing the capillary holding force of oil is considered a possible mechanism for increasing oil recovery from oil-wet rock. The capillary pressure curve shows that a relatively large increase in the oil recovery from oil-wet samples will occur if the IFT decreases and the gravity force becomes a dominant force.

Filtering pore chanels distribution density in Western Siberia

It is well known that information on filter channels distribution density can be obtained based on the data of core samples capillary studies in laboratory conditions. The curve of the fractional participation of pore channels in filtration, as a rule, is obtained by numerical processing of the capillary studies results. In this study, using a generalized mathematical model of capillary curves, an analytical solution is obtained for filtration channels distribution density by size in the conditions of Western Siberia reservoirs. The work shows that the main share in the filtration is taken by pore channels, the sizes of which are close to the maximum value. The density function of the filtering channels is mainly determined by the maximum radius and heterogeneity of the pore channel size distribution. Keywords: capillary pressure curve; generalized model; distribution density; filtering channels.

Wettability of Carbonate Reservoir Rocks: A Comparative Analysis

Various methods have been proposed for the evaluation of reservoir rock wettability. Among them, Amott–Harvey and USBM are the most commonly used approaches in industry. Some other methods, such as the Lak and modified Lak indices, the normalized water fractional flow curve, Craig’s triple rules of thumb, and the modified Craig’s second rule are based on relative permeability data. In this study, a set of capillary pressure curves and relative permeability experiments was conducted on 19 core plug samples from a carbonate reservoir to evaluate and compare different quantitative and qualitative wettability indicators. We found that the results of relative permeability-based approaches were consistent with those of Amott–Harvey and USBM methods. We also investigated the relationship between wettability indices and rock quality indicators RQI, FZI, and Winland R35. Results showed that as the rock quality indicators increased, the samples became more oil-wet.

Analysis of the bounded and unbounded forms of USBM wettability index

Understanding wettability is important in many processes where porous media and fluids are in contact. The U.S. Bureau of Mines (USBM) is one of the industry standard techniques for measuring wettability. This index is calculated as USBM=lg(A1A2), where A1 and A2 are the areas under capillary pressure curves of oil-drive and water-drive processes, respectively. Usually, the USBM is mistakenly assumed to vary over the range of −1 to 1 and compared with other indices. In this study we indicate that the lower and upper bounds of this index are not fully known in practice. As a result, comparison between USBM and other indices may cause erroneous interpretations due to dissimilar ranges of variation. In addition, even during examining the USBM of a sample it may not be possible to accurately interpret its wettability. We highlight the bounded form of the USBM index (denoted as USBM∗=A1−A2A1+A2), which varies over the range of −1 to 1, and suggest that it should replace the traditional form of USBM index. Twenty limestone core-plugs were collected from Asmari and Fahlian formations in two Iranian fields. These samples were used for performing primary imbibition relative permeability measurements, as well as primary imbibition and secondary drainage capillary pressure tests. These experiments are used to show the differences between USBM and USBM∗ in comparative studies and compare them against other indices of Amott-Harvey, Lak and modified Lak.

Sequential implicit vertex approximate gradient discretization of incompressible two-phase Darcy flows with discontinuous capillary pressure

This work deals with sequential implicit schemes for incompressible and immiscible two-phase Darcy flows which are commonly used and well understood in the case of spatially homogeneous capillary pressure functions. To our knowledge, the stability of this type of splitting schemes solving sequentially a pressure equation followed by the saturation equation has not been investigated so far in the case of discontinuous capillary pressure curves at different rock type interfaces. It will be shown here to raise severe stability issues for which stabilization strategies are investigated in this work. To fix ideas, the spatial discretization is based on the Vertex Approximate Gradient (VAG) scheme accounting for unstructured polyhedral meshes combined with an Hybrid Upwinding (HU) of the transport term and an upwind positive approximation of the capillary and gravity fluxes. The sequential implicit schemes are built from the total velocity formulation of the two-phase flow model and only differ in the way the conservative VAG total velocity fluxes are approximated. The stability, accuracy and computational cost of the sequential implicit schemes studied in this work are tested on oil migration test cases in 1D, 2D and 3D basins with a large range of capillary pressure parameters for the drain and barrier rock types. It will be shown that usual splitting strategies fail to capture the right solutions for highly contrasted rock types and that it can be fixed by maintaining locally the pressure saturation coupling at different rock type interfaces in the definition of the conservative total velocity fluxes. The numerical investigation of the sequential schemes is also extended to the widely used finite volume Two-Point Flux Approximation spatial discretization.

Enhancement of permeability estimation by high order polynomial regression for capillary pressure curve correlation with water saturation

Suggesting a cost-effective and straightforward approach is indispensable for obtaining permeability estimates in carbonate reservoirs utilizing available well logs. In this study, several procedures were conducted to reach an optimum approach, primarily by constructing a correlation between capillary pressure and water saturation using core data plotted and utilized a good polynomial regression to obtain a better relationship, which leads to calculating the permeability. The second step is to use different theoretical models which Tixier introduces, Timur, Coats, and Dumanior, which resulted not good matching with the permeability from core analysis and modified Brown and Husseini correlation which used and gave better matching than others correlations by comparing the results with the calculated permeability depending on core data. The proposed approach in this study based on modified Husseini equation using the well logs data by applying Statistical regression techniques within capillary pressure prediction to enhance reservoir characterization can potentially advantage reservoir simulation efforts. Obtained results of permeability prediction based on capillary pressure correlation was examined for a certain well and compared with the measured permeability value of cores. There was a good matching between the predicted and measured permeability.

Machine Learning for Capillary Pressure Estimation

Summary Capillary pressure plays an essential role in controlling multiphase flow in porous media and is often difficult to be estimated at subsurface conditions. The Leverett capillary pressure function J provides a convenient tool to address this shortcoming; however, its performance remains poor where there is a large scatter in the scaled data. Our aim, therefore, was to reduce the gaps between J curves and to develop a method that allows accurate scaling of capillary pressure. We developed two mathematical expressions based on permeability and porosity values of 214 rock samples taken from North America and the Middle East. Using the values as grouping features, we used pattern-recognition algorithms in machine learning to cluster the original data into different groups. In each wetting phase saturation, we were able to quantify the gaps between the J curves by determining the ratio of the maximum J to the minimum J. Graphical maps were developed to identify the corresponding group for a new rock sample after which the capillary pressure is estimated using the average J curve of the identified group and the permeability and porosity values of the rock sample. This method also provides better performance than the flow zone indicator (FZI) approach. The proposed technique was validated on six rock types and has successfully generated average capillary pressure curves that capture the trends and values of the experimentally measured data by mercury injection. Moreover, the proposed methodology in this study provides an advanced and a machine-learning-oriented approach for rock typing. In this paper, we provide a reliable and easy-to-use method for capillary pressure estimation in the absence of experimentally measured data by mercury injection.

Simulating volume-controlled invasion of a non-wetting fluid in volumetric images using basic image processing tools

A new algorithm is presented for simulating volume-controlled invasion of a non-wetting phase into voxel images. This method is complementary to the traditional morphological image opening method which mimics pressure-based invasion. A key advantage of the volume-based approach is that fluid configuration at any saturation between 0 and 1 can obtained rather than the irregularly and widely spaced saturation steps obtained by pressure-based methods. Because of the incremental increases in saturation, it becomes possible to correctly predict defending phase trapping, which is not the case when pressure-based steps are applied. The algorithm is verified by comparing to morphological image opening and obtains near perfect agreement at equal saturations as expected from theory. It is also demonstrated that a volume-controlled capillary pressure curve can be obtained that displays the characteristic jumps in capillary pressure. Moreover, the envelop of peak pressures yields the pressure-based capillary pressure obtained by morphological opening, so in fact the results of the proposed algorithm are a superset of the morphological approach. Finally, results are compared to multiphase lattice Boltzmann and qualitatively similar results were achieved in substantially less time. The lattice Boltzmann method is more flexible in terms of variable contact angle and inclusion of viscous effects, but for quasi-static volume-based injection of a non-wetting fluid, the proposed method is viable alternative.