Relative permeability (kr) functions are among the essential data required for the simulation of multiphase flow in hydrocarbon reservoirs. These functions can be measured in the laboratory using different techniques including the steady state displacement technique. However, relative permeability measurement of shale rocks is extremely difficult mainly because of the low/ultralow matrix permeability and porosity, dominant capillary pressure and stress-dependent permeability of these formations.
In this study, the impacts of stress and capillary end effects (CEE) on the measured relative permeability data were investigated. The steady state relative permeability (SS-kr) measurements were performed on Eagle Ford and Pierre shale samples. To overcome the difficulties regarding the kr measurements of shale rocks, a special setup equipped with a high-pressure visual separator (with an accuracy of 0.07 cc) was used. The kr data were measured at different total injection rates and liquid gas ratios (LGR). In addition, to evaluate the impacts of effective stress, the kr data of an Eagle Ford shale sample were measured at two different effective stresses of 1000 and 3000 psi.
From the experimental data, it was observed that the measured SS-kr data of the shale samples have been influenced by the capillary end effects as the data showed significant variation when measured at different injection rates (with the same LGR). This suggested that the liquid hold-up (i.e. capillary end effects) depends on the competition of capillary and viscous forces. In addition, it was shown that it is more necessary to correct the experimental kr data measured at the lower LGRs. Furthermore, different relative permeability curves were obtained when the kr data were measured at different effective stresses. This behavior was explained as the capillary pressure was expected to be more dominant at the higher effective stress.
The results from this study improve our understanding of unconventional mechanisms in shale reservoirs. It is evident that the behavior of unconventional reservoirs can be better predicted when more reliable and accurate relative permeability data are available. The outcomes of this study will be useful for accurate determination of such kr data.
As an enhanced oil recovery method (EOR), chemical flooding has been implemented intensively for some years. Low Salinity WaterFlooding (LSWF) is a method that has become increasingly attractive. The prediction of reservoir behaviour can be made through numerical simulations and greatly helps with field management decisions. Simulations can be costly to run however and also incur numerical errors. Historically, analytical solutions were developed for the flow equations for waterflooding conditions, particularly for non-communicating strata. These have not yet been extended to chemical flooding which we do here, particularly for LSWF. Dispersion effects within layers also affect these solutions and we include these in this work.
Using fractional flow theory, we derive a mathematical solution to the flow equations for a set of layers to predict fluid flow and solute transport. Analytical solutions tell us the location of the lead (formation) waterfront in each layer. Previously, we developed a correction to this to include the effects of numerical and physical dispersion, based on one dimensional models. We used a similar correction to predict the location of the second waterfront in each layer which is induced by the chemical's effect on mobility. In this work we show that in multiple non-communicating layers, material balance can be used to deduce the inter-layer relationships of the various fronts that form. This is based on similar analysis developed for waterflooding although the calculations are more complex because of the development of multiple fronts.
The result is a predictive tool that we compare to numerical simulations and the precision is very good. Layers with contrasting petrophysical properties and wettability are considered. We also investigate the relationship between the fractional flow, effective salinity range, salinity dispersion and salinity retardation.
This work allows us to predict fluids and solute behaviour in reservoirs with non-communicating strata without running a simulator. The recovery factor and vertical sweeping efficiency are also very predictable. This helps us to upscale LSWF by deriving pseudo relative permeability based on our extension of fractional flow and solute transport into such 2D systems.
Application of polymer flooding as a chemical Enhanced Oil Recovery (EOR) has increased over recent years. The main type of polymer used is partially hydrolyzed polyacrylamide (HPAM). This polymer still has some challenges especially with shear stability and injectivity that restrict its utility, particularly for low permeability reservoirs. Injectivity limits the possible gain by acceleration in oil production due to polymer flooding. Hence, good polymer injectivity is a requirement for the success of the operation. This paper aims to investigate the influence of formation permeability on polymer flow in porous media.
In this study, a combination of core flooding with rheological studies is presented to evaluate the influence of permeability on polymer in-situ rheology behavior. The in-situ flow of HPAM polymers has also been studied for different molecular weights. The effect of polymer preconditioning prior to injection was studied through exposing polymer solutions to different extent of mechanical degradation.
Results from this study reveal that the expected shear thinning behavior of HPAM that is observed in rheometer measurements is not observed in in-situ rheology in porous media. Instead, HPAM in porous media exhibits near-Newtonian behavior at low flow rates representative of velocities deep in the reservoir, while exhibiting shear thickening behavior at high flow rates representative of velocities near wellbore region. The pressure build-up associated with shear thickening behavior during polymer injection is significantly higher than pressure differential during water injection. The extent of shear thickening is high during the injection of high Mw polymer regardless of cores' permeability. In low permeable Berea cores, shear thickening and mechanical degradation occur at lower velocities although the degree of shear thickening is lower in Berea to that observed in high permeable Bentheimer cores. This is ascribed to high polymer retention in Berea cores that results in high residual resistance factor (RRF). Results show that preshearing polymer before injection into porous media optimizes its injectability and transportability through porous media. The effect of preshearing becomes favorable for the injection of high Mw polymers into low permeability formation.
This study discusses polymer in-situ rheology and injectivity, which is a key issue in the design of polymer flood projects. The results provide beneficial information on optimizing polymer injectivity, in particular, for low permeability porous media.
Shah, Swej (Delft University of technology) | As Syukri, Herru (Delft University of technology) | Wolf, Karl-Heinz (Delft University of technology) | Pilus, Rashidah (Universiti Teknologi PETRONAS) | Rossen, William (Delft University of technology)
Foam reduces gas mobility and can help improve sweep efficiency in an enhanced oil recovery process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that local pressure gradient exceeds a critical value (∇Pmin). Normally, this only happens in the near-well region. Away from wells, these requirements may not be met, and foam propagation is uncertain.
It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (
This article is an extension of a recent study (
Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, which then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities, however, the limit of foam propagation is reached at the lowest velocity tested. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and fg. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen, 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate - probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in ∇P and Sg) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injected rate.
Two upscaling exercises performed in 2013-14 and 2017-18 on two onshore green fields with conventional to viscous oil are presented, for which the upscaling tried to compensate the effects of grid coarsening, in particular the increase of numerical dispersion and the decrease of heterogeneity. Our methodology was to adjust the water/oil relative permeabilities called pseudo KRs in the coarse scale simulation, in order to reproduce the behavior in terms of pressure, rates, saturations and concentrations of the fine scale model, which was using microscopic rock KRs based on laboratory data.
As the upscaling depends on the fluid injected, it was done separately for waterflood and polymer flood. When done with polymer flood, the concentration of polymer had to be history matched also mainly by adjusting the Todd-Longstaff mixing parameter in addition to the KRs. As upscaling is case dependent, it was performed on several geological models, varying heterogeneity and grid size, but also rock KRs and even precocity of the polymer flood after some waterflood, to test the robustness of the approach.
It was found that pseudo-KRs for waterflood could be slightly degraded for viscous oils, whereas the upscaling was more neutral for conventional oils. This correlates well with field observation for viscous oils, where water production occurs generally a bit quicker than what numerical simulation predicts when using rock KRs, in absence of upscaling.
For polymer floods, which were considered in secondary or early tertiary mode, pseudo KRs were generally improved, mainly because the polymer steepened the saturation fronts, which can be well represented only with small lateral grid size.
The result of both upscaling exercises was that the increment of polymer flood versus waterflood was noticeably higher when computed on high resolution modelling. This is equivalent to saying that when using pseudo KRs resulting from this high resolution matching, the polymer increment on coarse grid is significantly higher than if computed without pseudo KRs. This improves the economic evaluation of the project, increasing the willingness to de-risk and implement early polymer floods on these fields.
Al-Rudaini, Ali (Heriot-Watt University) | Geiger, Sebastian (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Maier, Christine (Heriot-Watt University) | Pola, Jackson (Heriot-Watt University)
We propose a workflow to optimise the configuration of multiple interacting continua (MINC) models and overcome the limitations of the classical dual-porosity model when simulating chemically enhanced oil recovery processes. Our new approach captures the evolution of the concentration front inside the matrix, which is key to design a more effective chemically enhanced oil recovery projects in naturally fractured reservoirs. Our workflow is intuitive and based on the simple concept that fine-scale single-porosity models capture fracture-matrix interaction accurately and can hence be easily applied in a commercial reservoir simulator. Results from the fine-scale single-porosity system are translated into an equivalent MINC method that yields more accurate results than the classical dual-porosity model or a MINC method where the shells are arbitrarily selected.
Our approach does not require the tuning of capillary pressure curves ("pseudoisation"), diffusion coefficients, MINC shells, or the generation of recovery type curves, all of which have been suggested in the past to model more complex recovery processes. A careful examination of the fine-scale single-porosity model ("reference case") shows that a number of nested shells emerge, describing the advance of the concentration and saturation fronts inside the matrix. The number of shells is related to the required degree of refinement, i.e. the number of shells, in the improved MINC model. Using the results from a fine-scale single-porosity simulation to set up the shells in the MINC model is easy and requires only simple volume calculations. It is hence independent of the chosen simulator.
Our improved MINC method yields significantly more accurate results compared to a classical dual-porosity model, a MINC method with equally sized shells, or a MINC model with arbitrarily refined shells for a number of recovery scenarios that cover a range of matrix wettabilities and permeabilities. In general, improved results can be obtained when selecting five or fewer shells in the MINC. However, the actual number of shells is case-specific. The largest improvement is observed for cases when the matrix permeability is low.
The novelty of our approach is the easy-to-use method to define shells for a MINC model to predict chemically enhanced oil recovery from naturally fractured reservoirs more accurately, especially in cases where the matrix has low permeability. Hence the improved MINC method is particularly suitable to model chemical EOR processes in (tight) fractured carbonates.
Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) reckons on accurate description of pore structure, dynamic petrophysical properties (e.g., directional permeability, saturation-dependent capillary pressure), and fluid distribution. However, techniques for reliable quantification of permeability and hydrocarbon saturation still rely on model calibration using core measurements. Furthermore, assessment of saturation-dependent capillary pressure has been limited to experimental measurements, such as mercury injection capillary pressure (MICP). The objectives of this paper include (a) developing a new multiphysics workflow to simultaneously quantify rock fabric features (e.g., porosity, tortuosity, and effective throat size) and hydrocarbon saturation from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements, (b) introducing rock physics models that incorporate the quantified rock fabric and partial water/hydrocarbon saturation for assessment of directional permeability and saturation-dependent capillary pressure, and (c) validating the reliability of the new workflow in pore- and core-scale domains.
To achieve these objectives, we introduce a new multiphysics workflow integrating NMR and electric measurements, honoring rock fabric, and minimizing calibration efforts. We estimate water saturation from the interpretation of dielectric measurements. Next, we develop a fluid substitution algorithm to estimate the
The introduced multiphysics workflow provides accurate description of the pore structure and fluid distribution in partially water-saturated formations with complex pore structure. Moreover, this new method enables real-time well-log-based assessment of saturation-dependent capillary pressure and directional permeability (in presence of directional electrical measurements) in reservoir conditions, which was not possible before. Quantification of capillary pressure has been limited to measurements in laboratory conditions, where the differences in stress field reduce the accuracy of the estimates. We verified that the estimates of permeability, saturation-dependent capillary pressure, and throat-size distribution obtained from the application of the new workflow agreed with those experimentally determined from core samples. Finally, since the new workflow relies on fundamental rock physics principles, hydrocarbon saturation, permeability, and saturation-dependent capillary pressure can be estimated from well-logs with minimum calibration efforts, which is another unique contribution of this work.
Amarasinghe, Widuramina (NORCE Norwegian Research Centre AS, Norway, University of Stavanger, Norway) | Fjelde, Ingebret (NORCE Norwegian Research Centre AS, Norway, University of Stavanger, Norway) | Rydland, Jan-Aage (NORCE Norwegian Research Centre AS, Norway) | Guo, Ying (NORCE Norwegian Research Centre AS, Norway)
When CO2 is injected to aquifers, CO2 will be dissolved into the water phase and react with rock minerals. The CO2 dissolution into the water phase initiated by the diffusion, will increase the density of the water- phase and thereby accelerate convective flow of CO2. The objective of the presented work was to study the effects of permeability and wettability of porous media by visual investigation of mixing of supercritical CO2 (sCO2) with water by convectional flow at realistic reservoir conditions (pressure and temperature). This required construction of a high-pressure transparent 2D-cell that allows visualization of CO2 transport, and development of experimental procedures.
To develop the high-pressure Hele-Shaw 2D-cell, stress/strain calculations and simulations were carried out to select the best building materials for realistic working pressure and temperature and required dimensions to study convection. Porous media was prepared by glass beads of different sizes giving different permeability and wettability. The experiments were carried out at 100 bars and 50 °C using deionized water solution with Bromothymol blue (BTB) as pH indicator.
In the constructed Hele-Shaw 2D-cell, the cell volume was formed by two glass plates separated by an adjustable spacer. The cell thickness was 5.0 mm in the present study. The high-pressure 2D-cell has made it possible to investigate CO2-dissolution and mixing with water at pressures and temperatures realistic for CO2-storage reservoirs.
CO2 mixing and finger development in the water phase without the presence of porous media, was an instantaneous process. The rate for CO2 dissolution and mixing with water was found to increase with increasing permeability for water-wet porous media. The CO2 dissolution pattern was found to depend on the permeability. Fingering of CO2 rich high-density water was observed with the high permeable porous media. Piston-like displacement was observed in lower permeable porous media. No significant effect of wettability was observed in the high-pressure 2D cell experiments. After experiments, it was confirmed that the wettability of the oil-wet particles was changed during the CO2 dissolution experiments.
Zhang, Na (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad Sami (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
Modelling fluid flows in fractured reservoirs is crucial to many recent engineering and applied science research. Various numerical methods have been applied, including finite element methods, finite volume methods. These approaches have inherent limitations in accuracy and application. Considering these limitations, in this paper, we present a novel mimetic finite difference (MFD) framework to simulate two phase flow accurately in fracture reservoirs.
A novel MFD method is proposed for simulating multiphase flow through fractured reservoirs by taking advantage of unstructured mesh. Our approach combines MFD and finite volume (FV) methods. Darcy's equation is discreted by MFD method, while the FV method is used to approximate the saturation equation. The resulting system of equations is then imposed with suitable physical coupling conditions along the matrix/ fracture interfaces. This coupling conditions at the interfaces between matrix and fracture flow involve only the centroid pressure of fractures, which brings some simplification in analysis. The proposed approach is applicable for three dimensional systems. Moreover, it is applicable in arbitrary unstructured gridcells with full-tensor permeabilities. Some examples are implemented to show the performance of MFD method. The results showed a big potential of our method to simulate the flow problems with high accuracy and application.
Guetni, Imane (IFP Energies nouvelles – Rueil-Malmaison Université de Lorraine, CNRS, LIEC - Nancy) | Marliere, Claire (IFP Energies nouvelles – Rueil-Malmaison) | Rousseau, David (IFP Energies nouvelles – Rueil-Malmaison) | Bihannic, Isabelle (Université de Lorraine, CNRS, LIEC - Nancy) | Pelletier, Manuel (Université de Lorraine, CNRS, LIEC - Nancy) | Villieras, Frédéric (Université de Lorraine, CNRS, LIEC - Nancy)
Chemical EOR is now considered as an attractive option for sandstone reservoirs with permeability below 100mD, in particular where lack of gas supply does not allow gas injection (
Beyond a few reference textbooks (
In the case of porous media with low permeability for chemical EOR (below 100mD), typically characterized by small pores throats and complex mineralogical composition, thoses issues are all the more important. Low permeability sandstones are usually rich in clay, responsible for high polymer retention (