Oil Relative Permeability Research Articles

Accurate Modelling of Pore-Scale Films and Layers for Three-Phase Flow Processes in Clastic and Carbonate Rocks with Arbitrary Wettability

Three-phase flow is a key process occurring in subsurface reservoirs, for example, during $$\text{ CO }_2$$ sequestration and enhanced oil recovery techniques such as water alternating gas (WAG) injection. Predicting three-phase flow processes, for example, the increase in oil recovery during WAG, requires a sound understanding of the fundamental flow physics in water- to oil-wet rocks to derive physically robust flow functions, i.e. relative permeability and capillary pressure. In this study, we use pore-network modelling, a reliable and physically based simulation tool, to predict the flow functions. We have developed a new pore-scale network model for rocks with variable wettability, from water- to oil-wet. It comprises a constrained set of parameters that mimic the wetting state of a reservoir. Unlike other models, it combines three main features: (1) A novel thermodynamic criterion for formation and collapse of oil layers. The new model hence captures wetting film and layer flow of oil adequately, which affects the oil relative permeability at low oil saturation and leads to accurate prediction of residual oil. (2) Multiple displacement chains, where injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows for the accurate modelling of the mobilisation of many disconnected phase clusters that arise, in particular, during higher order WAG floods. (3) The model takes realistic 3D pore-networks extracted from pore-space reconstruction methods and CT images as input, preserving both topology and pore shape of the sample. For water-wet systems, we have validated our model with available experimental data from core floods. For oil-wet systems, we validated our network model by comparing 2D network simulations with published data from WAG floods in oil-wet micromodels. This demonstrates the importance of film and layer flow for the continuity of the various phases during subsequent WAG cycles and for the residual oil saturations. A sensitivity analysis has been carried out with the full 3D model to predict three-phase relative permeabilities and residual oil saturations for WAG cycles under various wetting conditions with different flood end-points.

Effect of Temperature on Two-Phase Relative Permeabilities of Heavy Oil, Water, Carbon Dioxide, and Methane Determined by Displacement Technique

Two coreflood setups were used to measure heavy oil–water, heavy oil–carbon dioxide, and heavy oil–methane relative permeabilities. Using fractional effluents measured with precision meters and differential pressure data records, the Johnson–Bossler–Naumann technique was applied to calculate two-phase relative permeability in a consolidated sandstone core. In order to investigate the effect of temperature on the shape of relative permeability curves, a series of coreflood tests was conducted at three different temperatures (28, 40, and 52 °C) for each fluid pair. Analysis of the data obtained for the heavy oil–water system showed a linear increase of about 65% and 50% in water relative permeabilities when temperature ranged from 28 to 40 °C and 40 to 52 °C, respectively. However, although the oil relative permeability curve showed an increase of about 70% when temperature increased from 28 to 40 °C, it was dramatically decreased by about 30% when temperature was increased from 40 to 52 °C. In the case of heavy oil–gas a different effect was observed for methane and carbon dioxide. Although both methane and carbon dioxide relative permeabilities increased nonlinearly at higher temperatures, oil relative permeability in the presence of carbon dioxide decreased when temperature increased. In contrast, in the presence of methane, oil relative permeability experienced a reduction of 80% from 28 to 40 °C followed by a considerable increase of 15-fold from 40 to 52 °C.

Experimental Study of Temperature Effect on Oil Relative Permeability in Porous Media

In the modeling of thermal recovery processes of heavy oil, it is important to know the oil primary relative permeability in the reservoir; moreover we have to be aware of effects of the temperature on oil relative permeability as well. In this study, a sand pack of quartz (SiO2) has been used to simulate and make a porous medium. Quartz is naturally water wet. During experiments there was no change in the pore volume of the media at different temperatures because of the low expansion coefficient of quartz. The fluid used in experiments is engine oil 50. Glass pipes with length of 91cm and diameter of 2.6cm have been used in the experiments. At first, columns have been filled with sand, which sand grains had different diameters, then carbon dioxide was injected to the columns to deplete the air in the pores , then the porous media have been saturated with water to calculate the porosity using the scale model. In addition according to Darcys law in steady state, the absolute permeability was calculated. In the next step, oil was injected to columns until the water saturation reached connate water saturation and finally, water injection was begun to get residual oil saturation (Sor). Experiments results showed that increase of temperature increases the oil relative permeability, note that wetability was constant. Increasing the temperature decreases the oil viscosity then this reduction causes the fluid to move easier and its velocity increases as well.

Three-Phase Pore-Network Modeling for Reservoirs With Arbitrary Wettability

Summary Oil reservoirs have structural heterogeneities across multiple length scales and, particularly in carbonates, complexly distributed wettabilities. The interplay of structural and wettability heterogeneities is the fundamental control for sweep efficiency and oil recovery. This interplay must be captured in physically robust flow functions, such as relative permeability and capillary pressure functions. Such flow functions then allow us to choose the best improved-oil-recovery (IOR) or enhanced-oil-recovery (EOR) process and forecast oil recovery with adequate precision. Obtaining flow functions for reservoir rocks with varying wettability is a challenging task, especially when three fluid phases coexist. In this work, we use pore-network modeling, a reliable and physically based simulation tool, to predict three-phase flow functions. We have developed a new pore-scale network model for rocks with variable wettability. Unlike other models, this model combines three new and important features. (1) Our network model comprises a novel thermodynamic criterion for the formation and collapse of oil layers. This captures film/layer flow of oil adequately, which affects the oil relative permeability at low oil saturation. We can therefore predict residual oil more accurately. (2) We implemented multiple displacement chains, in which injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows us to accurately model the mobilization of disconnected phase clusters that arise during higher-order [water-alternating-gas (WAG)] floods. Again, this feature is key to a better prediction of residual oil saturation (ROS). (3) Our model takes realistic 3D pore networks extracted from pore-space reconstruction methods and X-ray computerized-tomography (CT) images as input. This preserves both topology and pore shape of the rock, providing better estimates of phase conductivities and relative permeability. We have validated our model by use of available experimental data for a range of wettabilities and demonstrated the impact of single vs. multiple displacement on residual oil. We also used a proof-of-concept study in which we use flow functions for different wettabilities that have been computed with our model in field-scale reservoir simulations to forecast oil recovery during tertiary gas injection. These results are compared with predictions that used empirical flow functions. Flow functions computed by our network model gave higher oil recovery than corresponding flow functions calculated by empirical models; oil recovery increases with decreasing water-wetness. This shows that the pore-scale physics encapsulated in our new network model leads to the right emergent behavior at the reservoir scale.

A New Unsteady-State Model for Calculating Oil-Water Relative Permeability of Low-Permeability/Ultra-Low Permeability Reservoirs

Oil and water relative permeabilities are main coefficients in describing the fluid flow in porous media; however, oil and water relative permeability for low - ultra low perm oil reservoir can not be obtained from present correlations. Based on the characteristics of oil and water flow in porous media, the model for calculating the oil and water relative permeability of low and ultra-low perm oil reservoirs, which considering effects of threshold pressure gradient and capillary pressure, has been established. Through conducting the non-steady oil and water relative permeability experiments, oil and water relative permeability curves influenced by different factors have been calculated. Results show that: the threshold pressure gradient more prominently affects the oil and water relative permeability; capillary pressure cannot influence the water relative permeability but only the oil relative permeability. Considering effects of threshold pressure gradient and capillary pressure yields the best development result, and more accordant with the flow process of oil and water in low – ultra low perm oil reservoirs.

Measurement of three-phase relative permeabilities

Abstract Three-phase relative permeabilities of water-wet and oil-wet outcrops with two saturating histories (DDI and IID) are investigated by steady physical simulation experiments. CT Dual Energy Simultaneous Scanning (DESS) method was introduced to measure three-phase saturations accurately, which can eliminate the end effect. The relative permeability of each phase at a given saturation is calculated by Darcy law. The experiment results clearly show that for water-wet cores, the isoperms of water are straight lines, which means that the relative permeability of water depends on water saturation only. The isoperms of oil are curves concave towards 100% oil saturation point, and the isoperms of gas are curves convex towards 100% gas saturation point, which means that the relative permeabilities of oil and gas depend on all the three phase saturations. For oil-wet cores, all the isoperms of water, oil and gas are curves convex towards their 100% saturation points, which means that the relative permeabilities of water, oil and gas depend on all the three phase saturations. In addition, the isoperms of wetting phase are similar for the two saturation histories, while those of non-wetting phases are quite different. Though the isoperms are the same in shape, they are different in values and positions.

Gas–oil relative permeability at near miscible conditions: An experimental and modeling approach

Reliable relative permeability curves of oil–gas systems are important for successful simulation and modeling of gas injection, especially when the miscibility condition approaches. In this work, the relative permeability of a CO2-light oil system has been measured under different conditions, using the Civan and Donaldson (1989) [13] method. Dolomite and sandstone core samples were used in the experiments. The minimum miscibility pressure was calculated using an empirical correlation, as well as slim-tube simulation. Due to some controversial assumptions of the Civan and Donaldson method, such as immiscible and incompressible displacement, history matching was used for predicting the reliable relative permeability of each phase at near miscible conditions. The Civan and Donaldson method was used to predict the relative permeabilities as the initial guesses for the history matching. We found that the Civan and Donaldson method underestimates oil relative permeability. Moreover, the effect of near miscibility on the gas phase relative permeability curve was stronger and the intersection point of the oil and gas phase relative permeability curves occurred at lower gas phase saturations. The results are helpful for understanding near miscible relative permeability behavior and provide knowledge on fluid flow at low IFT conditions during gas injection projects.

Experimental Study on Fluid-Solid Coupling Seepage Flow in Putaohua Reservoir

According to existing fluid-solid coupling models, reasonable range and control technology of pressure depression cone has not be formed in Putaohua reservoir. In this paper, using laboratory experiment, the relationship between rock elastic-plastic deformation, single phase permeability of oil or water and relative permeability curves has been measured and the following important facts has been established: oil well bottom hole pressure which is lower than formation pressure is in a reasonable range during the initial stage of commissioning, and a gently pressure depression cone is formed between the formation and wellbore, that can reduce the permeability loss by compaction settlement and particle migration and return to production in reasonable bottom hole pressure while the water flooding takes effect and thus enhance the oil recovery.

Effect of Temperature on Athabasca Type Heavy Oil – Water Relative Permeability Curves in Glass Bead Packs

There have been a number of somehow contradictory reports in the literature on the effect of temperature on oil and water relative permeabilities. Although some authors have reported the dependence of relative permeability curves on temperature, others have attributed these dependencies to artifacts inherent in unsteady-state method of relative permeability measurement. In order to further investigate the impact of temperature changes on the relative permeability data, we have conducted laboratory core flooding experiments on heavy oil systems. The porous media used was glass bead packs, and the Athabasca type bitumen with varying viscosities was displaced by hot water. The history matching technique was conducted on production and pressure differential data to get the relative permeability curves. Results indicated that generally the increase in initial water saturation and the decrease in residual oil saturation are expected by increasing temperature. However, viscous instabilities can rule out the above mentioned trends. No temperature dependency of either oil or water relative permeability can be justified in our tests. The changes in relative permeabilities by temperature are probably related to experimental artifacts, viscous fingering and changes in oil to water viscosity ratio and not fundamental flow properties.

Estimation of the Water–Oil Relative Permeability Curve from Radial Displacement Experiments. Part 2: Reasonable Experimental Parameters

The capillary pressure is the key parameter to affect the inversion accuracy of the water–oil relative permeability curve. The existing analytical inversion methods have neglected the influence of capillary pressure, which may cause low precision for the estimated relative permeability curve in some cases. On the basis of the numerical inversion method for the water–oil relative permeability curve established in part 1 (10.1021/ef300018w), taking the one-dimensional radial numerical experiment for example, the rules of relative permeability variation and influence of different displacement conditions on relative permeability deviation when neglecting the capillary pressure are investigated. With regard to water-wet cases whose oil–water viscosity ratio is greater than 1.5, it indicates that the estimated water-phase relative permeability curve is higher and the estimated oil-phase relative permeability curve is lower compared to the true relative permeability curve when the capillary pressure is neglected...

Estimation of the Water–Oil Relative Permeability Curve from Radial Displacement Experiments. Part 1: Numerical Inversion Method

The water–oil relative permeability curve is mainly obtained from linear displacement experiments. Few radial displacement experiments have been carried out. In the process of linear displacement experiments, the flow properties of the water–oil two phase are linear. Nevertheless, it is radial near the bottom holes of an actual reservoir. With regard to both kinds of displacement experiments, the flow characteristics are various, which may result in great deviation to apply the linear calculation theory of the relative permeability curve to an actual reservoir. As a result of the above-mentioned problems, on the basis of radial displacement experiments, using the Levenberg–Marquardt algorithm for automatic history matching, this paper performs optimization of production performance and relative permeability representation models. Finally, a novel numerical inversion method for the radial water–oil relative permeability curve is established. A test based on the basic data of a radial laboratory displacemen...

Numerical Analysis of Imbibition Front Evolution in Fractured Sandstone under Capillary-Dominated Conditions

Fractures serve as primary conduits having a great impact on the migration of injected fluid into fractured permeable media. Appropriate transport properties such as relative permeability and capillary pressure are essential for successful simulation and prediction of multi-phase flow in such systems. However, the lack of a thorough understanding of the dynamics governing immiscible displacement in fractured media, limits our ability to properly represent their macroscopic transport properties. Previous experimental observations of imbibition front evolution in fractured rocks are examined in the present study using an automated history-matching approach to obtain representative relative permeability and capillary pressure curves. Predicted imbibition front evolution under different flow conditions resulted in an excellent agreement with experimental observations. Sensitivity analyses, in combination with direct experimental observation, allowed exploring the competing effects of relative permeability and capillary pressure on the development of saturation distribution and imbibing front evolution in fractured porous media. Results show that residual saturations are most sensitive to matrix relative permeability to oil, while the ratio of oil and water relative permeability, rock heterogeneity, boundary condition, and matrix–fracture capillary pressure contrast, affect displacement shape, speed, and geometry of the imbibing front.

Simultaneous Estimation of Relative Permeability and Capillary Pressure Using Ensemble-Based History Matching Techniques

An ensemble-based technique has been developed and successfully applied to simultaneously estimate the relative permeability and capillary pressure by history matching the observed production profile. Relative permeability and capillary pressure curves are represented using a power-law model. Then, forward simulation is performed with the initial coefficients of the power-law model, all of which are to be tuned automatically and finally determined once the observed data is assimilated completely and history matched. The newly developed technique has been validated by a synthetic coreflooding experiment with two scenarios. The endpoints are fixed for the first scenario, whereas they are completely free in the second scenario. Simultaneous estimation of relative permeability and capillary pressure has been found to improve gradually as more observation data is assimilated. There exists an excellent agreement between both the updated relative permeability and the capillary pressure and their corresponding reference values, once the discrepancy between the simulated and the observed production history has been minimized. Compared with coefficients of capillary pressure curve, coefficients of relative permeability curves, irreducible water saturation, and residual oil saturation are found to be more sensitive to the observed data. In addition, water relative permeability is more sensitive to the observation data than either oil relative permeability or capillary pressure. It is shown from its application to a laboratory coreflooding experiment that relative permeability and capillary pressure curves can be simultaneously evaluated once all the experimental measurements are assimilated and history matched.

Quantitative Prediction Model for the Water–Oil Relative Permeability Curve and Its Application in Reservoir Numerical Simulation. Part 2: Application

Quantitative Prediction Model for the Water–Oil Relative Permeability Curve and Its Application in Reservoir Numerical Simulation. Part 2: Application

Quantitative Prediction Model for the Water–Oil Relative Permeability Curve and Its Application in Reservoir Numerical Simulation. Part 1: Modeling

The water–oil relative permeability curve has a great effect on the rules of water cut increase and production variation. It is one of the most important data in reservoir development. With regard to a reservoir with a high degree of heterogeneity, the flow properties are various in different positions of the reservoir. Therefore, neither a single average relative permeability curve for the whole reservoir nor different curves for different sedimentary facies can precisely describe the reservoir flow characteristics, which will cause great difficulties for the remaining oil prediction and potential tapping. Therefore, it is of great importance to build a prediction model for the water–oil relative permeability curve, which can provide a calculation theory of the relative permeability curve for reservoir simulation using different relative permeability curves in different grid cells. The existing prediction models for the relative permeability curve have established the correlations between petrophysical p...

Wettability Altering Secondary Oil Recovery in Carbonate Rocks

Carbonate rocks tend to be oil-wet, leading to lower oil relative permeability and lower oil recovery in the life of a waterflood, which is about 3 pore volume (PV) injection. The goal of this work is to improve oil recovery during secondary waterflood by wettability alteration because of a surfactant addition. The effect of the surfactant is studied by contact angle measurement, spontaneous imbibition, and secondary water/surfactant flood in reservoir cores. The contact angle changes from oil-wet to intermediate-wet in the presence of 0.2 wt % of a surfactant. Brine (without surfactant) does not imbibe into the core spontaneously, but surfactant brine imbibes to the extent of 20% of the oil in place. Secondary waterflooding recovers about 62% of the oil in about 3 PV injection and 80% in about 16 PV. Secondary surfactant flooding recovers about 85% in about 3 PV and about 90% in 4 PV. Injection of 1 PV of surfactant solution followed by waterflood also recovers about 83% of the oil in a total injection of 3 PV. This increase in oil recovery from 62 to 85% by wettability alteration is very significant and needs to be evaluated at the field scale.

Flow coupling during three-phase gravity drainage

We measure the three-phase oil relative permeability k(ro) by conducting unsteady-state drainage experiments in a 0.8 m water-wet sand pack. We find that when starting from capillary-trapped oil, k(ro) shows a strong dependence on both the flow of water and the water saturation and a weak dependence on oil saturation, contrary to most models. The observed flow coupling between water and oil is stronger in three-phase flow than two-phase flow, and cannot be observed in steady-state measurements. The results suggest that the oil is transported through moving gas-oil-water interfaces (form drag) or momentum transport across stationary interfaces (friction drag). We present a simple model of friction drag which compares favorably to the experimental data.

Radio Frequencies as an Oil-Production Stimulation Method

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 133085, ’Quantum Effects Imparted by Radio Frequencies as a Stimulation Method of Oil Production - Part II,’ by J. Mike Brown, SPE, Harold L. Becker, and Greg Darby, SPE, BJ Services, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed. Tuned energy waves alter molecular bonds in the well-tubular and near-wellbore regions to stimulate production by disrupting damaging deposits and altering relative permeability. New studies elucidate the action mechanism and the range of the application. Introduction The full-length paper is a continuation of paper SPE 124144 in which a method of stimulating producing wells by use of electromagnetic frequencies was described. The frequencies used by the device are in the range used in nuclear-magnetic- and electron-spin-resonance spectroscopy. The mode of action is thought to be the result of changing the nuclear- and electron-spin states of molecules such as paraffin waxes and altering the degree of hydrogen bonding and charge induction that allow aggregation and networking of the wax particles. A recent study of the process provided additional insight to explain the action mechanism and to aid candidate selection. Laboratory core-flow studies showed that wettability reversal can increase production by removal of production impairments. Not all treated wells have shown measureable increases in production, and additional work is needed to improve candidate selection. Some wells that did not show a production increase benefited in reduction or elimination of workover and conventional chemical treatments. The electromagnetic frequencies used in this iteration of the device target near-wellbore damage resulting from wettability changes caused by hydrocarbon-based deposition or past production practices that resulted in this type of damage. These frequencies are in the radio-frequency (RF) band of electromagnetic radiation. Relative Permeability Modification Core-flow studies on native oil-wet sandstone were conducted to evaluate the effect of RF treatment on the relative permeability of oil and water. During core preparation, differential pressure and flow rate were monitored to calculate effective permeability to oil at irreducible water saturation (KoSwi). The sample was unloaded from the core holder and transported to a laboratory RF unit for treatment. Following a 15-minute RF-treatment period, the sample was reloaded into the core holder at 180°F. Alternating cycles of mineral oil, 2% KCl, and then mineral oil again were injected. Differential pressure and flow rate were recorded and the permeability was calculated. The sample was unloaded from the core holder and subjected to a second 15-minute treatment. The sample was reloaded into the core holder at 180°F and alternating cycles of mineral oil and 2% KCl were injected. Differential pressure and flow rate were recorded, and the permeability was calculated.

Downscaled Capillary Pressure and Relative Permeability of Small Cores for Network Model Validation

This paper presents the results of drainage capillary pressure and relative permeability measurements made on cores having different bulk volumes ranging from 0.5 to 12 cm3. The aim of the experiments was to provide reliable experimental data which can be used to validate the predictive value of micro-CT based network models for capillary pressure and relative permeability. The micro-CT based network models use realistic networks constructed from the X-ray images of the rock samples having a typical bulk volume of 0.3 cm3. Experimental data for drainage capillary pressure were obtained using the centrifuge technique. The results of the largest cores were verified by the data obtained on the same sample using the porous plate technique. Relative permeability data were obtained by history matching the unsteady state displacement data. Homogeneous model sandstones (Berea and Bentheim) and carbonate (Mt. Gambier) were used in the experiments. Air-brine and oil-brine fluid-systems were used for drainage capillary pressure and relative permeability measurements, respectively. The relative permeability data were compared with those predicted from empirical and geometry based models using capillary pressure data. Good agreement was obtained for the drainage capillary pressure measured on all samples used. The residual saturations obtained from the cores used in the displacement experiments were also in good agreement. The models were found to predict relative permeability of oil and water with varying degrees of success. For water relative permeability, the Pirson model predicts the experimental data successfully while the Corey, Corey-Brooks/Burdine and van Genuchten/Burdine models predict the data of oil relative permeability better than the others. The results demonstrate for the first time that reliable drainage capillary pressure and relative permeability measurements can be made on small model sandstone and carbonate cores of representative scales used in micro-CT-imaging.

Convection at the Edge of a Steam-Assisted-Gravity-Drainage Steam Chamber

Summary Steam-assisted gravity drainage (SAGD) has become the preferred process to recover bitumen from Athabasca deposits in Alberta. The method consists of a lower horizontal production well, typically located approximately 2 m above the base of the oil zone, and an upper horizontal injection well located roughly 5 to 10 m above the production well. Steam flows from the injection well into a steam chamber that surrounds the wells and releases its latent heat to the cool oil sands at the edge of the chamber. This research re-examines heat transfer at the edge of the steam chamber. Specifically, a new theory is derived to account for convection of warm condensate into the oil sand at the edge of the chamber. The results show that, if the injection pressure is higher than the initial reservoir pressure, convective heat transfer can be larger than conductive heat transfer into the oil sand at the edge of the chamber. However, enhancement of the heat-transfer rate by convection may not necessarily imply higher oil rates; this can be explained by relative permeability effects at the chamber edge. As the condensate invades the oil sand, the oil saturation drops and, consequently, the oil relative permeability falls. This, in turn, results in the reduction of the oil mobility, despite the lowered oil viscosity because of higher temperature arising from convective heat transfer.