Oil-water Relative Permeability Research Articles

New water drive characteristic curves at ultra-high water cut stage

Abstract A function expression of the oil-water relative permeability ratio with normalized water saturation at high water saturation was proposed based on statistics of measured oil-water relative permeability data in oilfields. This expression fits the later section of conventional relative permeability ratio curve more accurately. Two new water drive characteristic curves at the ultra-high water cut stage (fw>90%) were derived by combining the new oil-water relative permeability ratio expression and reservoir engineering method. Then, the numerical simulation results of five-point well pattern and production data of Yangerzhuang Oilfield and Liuzan Oilfield were used to verify the adaptability of the new water drive characteristic curves. The results showed that the new water drive characteristic curves are more accurate than conventional water drive characteristic curves after A type and B type water drive curves rise, and can be used to predict production performance at ultra-high water cut stage, ultimate recovery efficiency and recoverable reserves.

Influence of Individual Ions on Oil/Brine/Rock Interfacial Interactions and Oil–Water Flow Behaviors in Porous Media

The low salinity effect (LSE) in enhanced oil recovery (EOR) is widely accepted. However, its underlying mechanisms remain unclear due in part to the complex interactions at the oil/brine/rock interface. The chemistry of brine largely depends on the ionic composition. Thus, in this work, attention was placed on the roles of individual ions and salinity in LSE through direct measurements of oil/brine/rock interfacial behaviors, oil displacement efficiencies, and oil–water relative permeability in sandstone porous media. The results showed that the oil/water interfacial tensions (IFTs) were weakly dependent on ion and the lowest IFTs were generated at the salinities of 0.2–0.5 wt %. In contrast, the interfacial dilational modulus varied significantly with ion types and salinities due to the adsorption of polar components at the oil/water interface. Moreover, wettability alteration of the sandstone surface was found to be associated with the divalent ions in our work. As a result of the viscoelastic interfac...

Approximate Semi-analytical Solution for Injection–Falloff–Production Well Test: An Analytical Tool for the In Situ Estimation of Relative Permeability Curves

An injection–falloff–production test (IFPT) was originally proposed in Chen et al. (in: SPE conference paper, 2006. doi: 10.2118/103271-MS , SPE Reserv Eval Eng 11(1):95–107, 2008) as a well test for the in situ estimation of two-phase relative permeability curves to be used for simulating multiphase flows in porous media. Hence, we develop an approximate semi-analytical solution for the two-phase saturation distribution in an oil–water system during the flowback period of an IFPT according to the mathematical theory of waves. In fact, we show that the weak solution we construct for the saturation equation for the flowback period satisfies the Oleinik entropy condition and hence is unique. In addition, we allow the governing relative permeabilities during the flowback period to be different from the relative permeabilities during injection. Using the saturation solution with the steady-state pressure theory of Thompson and Reynolds, we obtain a solution for the wellbore pressure during the flowback period. By comparing results from our solution with those from a commercial numerical simulator, we show that our approximate semi-analytical solution yields accurate saturation profiles and bottom hole pressures history. The use of very small time steps and a highly refined radial grid is necessary to generate a good solution from a reservoir simulator. The approximate analytical pressure solution developed is used as a forward model to match pressure and water flow rate data from an IFPT in order to estimate reservoir rock absolute permeability and skin factor in conjunction with in situ imbibition and drainage water–oil relative permeabilities.

Unified relative permeability model and waterflooding type curves under different levels of water cut

Understanding the relative permeability of multiphase flow in porous media is crucial for the efficient development of waterflooding reservoirs. The semi-log linear relationship between oil-water relative permeability ratio (kro/krw) and water saturation (Sw) has been commonly used to derive waterflooding type curve—an empirical and practical tool for the forecast of production performance. However, recent experiments suggest that owing to the highly dispersed oil in water phase, the kro/krw vs Sw correlation deviates from a straight line in a semi-log plot at high water-cut stage (>90%). Considering the linear model of ln(kro/krw) vs Sw fails to describe the multiphase flow behavior for average water saturation greater than ~65%, we present a unified mathematical model to account for different water saturations and develop two type curves to predict the waterflooding performance. Data from previous literatures, numerical simulations, and actual oilfields are employed to examine the capability of the proposed method. In comparison with traditional Type-A and -B curves, in which the correlation of ln(kro/krw) vs Sw is linear, the proposed model provides remarkably accurate results. Although the nonlinear relationship occurs only at high water saturations, neglecting this feature of the relative permeability curve can cause a significant error in the prediction. This work provides a comprehensive model of ln(kro/krw) vs Sw and new Type-A and -B curves for reservoirs at high water-cut stage, which are beneficial for accurate performance forecasts for the entire duration of waterfloods.

Enhanced Oil Recovery of Low-Permeability Cores by SiO2 Nanofluid

This study investigated the mechanisms and performance of SiO2 nanofluid for enhanced oil recovery (EOR) in low-permeability cores. Three-phase contact angles for quartz/oil/brine systems were measured, and the microscopic imbibition characteristics of nanofluids in a capillary were observed through visualization experiments. In addition, the effects of the adsorption of the nanoparticles on the oil–water relative permeability was studied using core displacement tests. Furthermore, a total of 11 core flooding tests were performed, and the effects of injection parameters, such as nanoparticle concentration, injection rate, and injection scheme, on the oil recovery were investigated. Wettability alterations were observed among quartz/oil/brine systems that contributed to higher displacement efficiencies in microscopic imbibition tests. Relative permeability measurements showed that, upon the adsorption of the nanoparticles, the irreducible water saturation and oil-phase relative permeability increased where...

Optimization of polymer flooding design in conglomerate reservoirs

The polymer flooding can be a very promising, cost-effective enhanced oil recovery (EOR) strategy in the development of conglomerate oil reservoirs, especially when the reservoirs reach very high water-cut in production. The key to success for a polymer flooding is to use the full potential of mobility control under the premise of good compatibility between polymer and reservoirs. Polymer is easy to be adsorbed and also potentially clogs the formations especially when the pressure gradient is small in the reservoir. Meanwhile, polymer efficient viscosity has a huge impact on polymer mobility control. The method of polymer flooding optimization design is described in a formation of interest called Karamay conglomerate reservoir (Xinjiang Province, China). We’ve compared the pore structure difference between conglomerates and sandstones, measured hydrodynamic characteristic sizes of polymer molecular and ensured the maximum polymer molecular weight and concentration for corresponding permeability. Then different pore structure cores were used to investigate the rheology of polymer transport in conglomerates and sandstones. A model were built by using the water-oil relative permeability curves and polymer rheology experimental data, which was utilized to calculate the minimum viscosity of the polymer solution required for a high-performance mobility control in polymer flooding. In the study we have found that 1) conglomerate with the shallower depth and tortuous pore structure has about three times shear rates than single pore structure sandstone in the same flow velocity; 2) the viscosity range of a high-performance polymer for conglomerate reservoirs is determined to be 25.1cP−29.4cP at shear rate of 7.34s−1 for Upper Karamay formation, and 8.6cP−12.8cPs at shear rate of 7.34s−1 for Lower Karamay formation. It implies that polymer flooding should be using by injection of polymer solutions in each layer.

Effect of temperature on the oil–water relative permeability for sandstone reservoirs

Temperature has a significant effect on oil–water relative permeability, which is very important in reservoir development. Considerable controversy persists regarding the effects of temperature and concerning how to obtain representative relative permeability curves. This work studies the effect of temperature on the oil–water relative permeability of tight sandstone and analyzes the influences of absolute permeability, clay mineral content, and pore throat structure on relative permeability curves at different temperatures. The results indicate that irreducible water saturation increases linearly with temperature increase, while residual oil saturation decreases nonlinearly with temperature increase. In addition, when temperature increases, both oil and water relative permeability increase under the same water saturation and the crossover saturation moves rightwards, which indicates that the system becomes more water-wet. Due to the significant effect of temperature on relative permeability, experimental results from lab tests cannot accurately reflect fluid flow characteristics under the reservoir condition. In order to overcome this problem, this paper proposes a novel method to translate lab results into reservoir values by combining the Johnson–Bossler–Naumann (JBN) technique and the empirical method. The comparison between the calculation and the lab results is consistent. The conclusions of the paper provide a valuable reference for laboratory tests under high temperature, and they can be used for preliminary evaluation purposes.

Modeling of Two-Phase Relative Permeability in Cambrian and Early Miocene Sandstone Reservoirs: A Case Study, Egypt

The relative permeability is the ratio of the effective permeability to the absolute permeability. Due to the importance of relative permeability in reservoir simulation, there is a dominant need to upscale it. So, several models were introduced to modeling the relative permeability. Some correlation models were dependent on capillary pressure measurements, while other models did not require such measurements. In this study, four relative permeability correlation models were chosen to apply them on two sandstone reservoir (labeled A and B) data sets. The two reservoirs belong to different ages and depositional environments. Both reservoirs are located in the Southern Gulf of Suez, Egypt. Reservoir A is the Nubian sandstone of Cambrian age. Reservoir B is the Nukhul clastic of Early Miocene age. The data sets include laboratory measurements of unsteady-state gas–oil relative permeability and steady-state water–oil relative permeability tests. The results indicate that the practical and modified Corey models were the most applicable model for the studied reservoirs. Additionally, prediction of relative permeability at saturation end points was carried out based on using routine core porosity and permeability by introducing new empirical equations. The relative permeability was used to identify rock wettability, water cut, water cutoffs and the areal and vertical sweep efficiencies.

Experimental investigation the effect of nanoparticles on the oil-water relative permeability

This paper presents the effects of the nanosilica particles on the water and oil relative permeability curves at reservoir conditions. Real reservoir crude oil sample was employed as an oil phase in relative permeability measurements. In addition, real carbonate reservoir rock samples were employed as a porous media in core displacement experiments. To determine relative permeability curves, the unsteady-state approach was employed in which Toth et al. method was applied to the recovery data points. By increasing the nanosilica content of the aqueous phase the oil relative permeability increased while the residual oil saturation decreased; however, by increasing the nanosilica concentration in the aqueous solution the water relative permeability decreased. The outcomes of this paper can provide a better understanding regarding chemically enhanced oil recovery (EOR) by nanoparticles. Moreover, relative permeability curves help us in the history matching section of reservoir simulation for any further EOR scenarios.

Acquisition and analysis of transient data through unsteady-state core flooding experiments

Dynamic displacement experiments and numerical two-phase flow estimation program are presented in this study. Unsteady-state core-flooding system was designed and utilized for oil–water dynamic displacement experiment. Two in situ sandstone core plug samples were used to investigate relative permeability via diesel and 3 wt % brine as non-wetting and wetting phase fluids. The transient data (pressure drop and produced fluid volume) were collected automatically for oil–water relative permeability computation. For relative permeability analysis, an inverse method program was constructed with four components: (a) an IMPE finite-difference numerical simulator of the flow through the core; (b) functional Cory-type power law model of relative permeability in terms of a set of adjustable parameters found by minimizing an objective function; (c) the objective function formed by the sum of the square of the differences between the observations and calculated data; (4) the Gauss–Newton with Levenberg–Marquardt modification procedure for the least-squares problem to minimize the objective function definition. All the above processes are embodied in relative-permeability calculation program, RCP, which is constructed in this study using FORTRAN language.

Effect of fines migration on oil–water relative permeability during two-phase flow in porous media

One of the main physical characteristics defining oil recovery during water injection is the phase relative permeability. Salinity of the formation water can significantly differ from the injected water and consequently affect the relative permeabilities.In the current work, we investigate the effect of fines migration on water and oil relative permeability. First, flow tests with piece-wise constant decreasing water salinity without oil are performed in order to identify the movable fine particles. Then the oil is displaced by the formation water from the sister-cores for a recovery assessment excluding the ion exchange processes. After re-saturation, oil is displaced by water with alternate salinity. The conditions of large-scale approximation, where the capillary pressure and dispersion effects are negligible, have been achieved in the tests. This allows the derivation of the modified Welge–JBN method to determine relative permeability from the performed tests. The obtained relative permeability curves for water exhibits an abnormal decline at high saturations, which is attributed to fines mobilization and straining yielding the water permeability decline.

Evolving simple-to-use method to determine water–oil relative permeability in petroleum reservoirs

Abstract In the current research, a new approach constructed based on artificial intelligence concept is introduced to determine water/oil relative permeability at various conditions. To attain an effective tool, various artificial intelligence approaches such as artificial neural network (ANN), hybrid of genetic algorithm and particle swarm optimization (HGAPSO) are examined. Intrinsic potential of feed-forward artificial neural network (ANN) optimized by different optimization algorithms are composed to estimate water/oil relative permeability. The optimization methods such as genetic algorithm, particle swarm optimization and hybrid approach of them are implemented to obtain optimal connection weights involved in the developed smart technique. The constructed intelligent models are evaluated by utilizing extensive experimental data reported in open literature. Results obtained from the proposed intelligent tools were compared with the corresponding experimental relative permeability data. The average absolute deviation between the model predictions and the relevant experimental data was found to be less than 0.1% for hybrid genetic algorithm and particle swarm optimization technique. It is expected that implication of HGAPSO-ANN in relative permeability of water/oil estimation leads to more reliable water/oil relative permeability predictions, resulting in design of more comprehensive simulation and further plans for reservoir production and management.

A New Correction Method for Oil–Water Relative Permeability Curve on the Basis of Resistivity and Water Saturation Relationship

Oil–water relative permeability curve constitutes important basic data in reservoir engineering. Given the influence of dead volume on experimental apparatus, the actual oil–water relative permeability curve cannot be obtained when the unsteady-state method is adopted to measure oil–water relative permeability. In this paper, on the basis of the analysis of the influence of dead volume on oil–water relative permeability, we summarize the conventional methods used to overcome dead volume and then propose the use of relationship theory between resistivity and water saturation to calibrate the oil–water relative permeability curve. This method mainly aims at to measure the resistance values at both ends of the core by using a resistance-measuring instrument. Meantime, the Archie formula is used to calibrate the relational expression of core resistivity and water saturation based on the steady-state experimental method. Therefore, the core of the actual cumulative oil production and the average water saturation can be calculated, and then oil–water relative permeability can be accurately computed without the influence of dead volume. By comparing the oil displacement process of dead volume calculated through two different methods (probability subtraction and resistivity methods), the crude oil in dead volume is found to be displaced at the beginning of the displacement. The oil–water relative permeability curve corrected through resistivity method can eliminate the influence of dead volume and iterative error in calculation, and is consistent with the law of the actual development of oilfield, which has certain theoretical and practical application values.

Analysis and Evaluation of Oil-water Relative Permeability Curves

Oil-water relative permeability curves are the characteristic curves of evaluating the oil-water infiltrating fluid and also are an important part of reservoir engineering studies. Through a large number of core flooding experiments, based on the establishment of oil-water relative permeability calculation models, the use of the function of the relative permeability curves divided these into the water phase concave, water phase convex and a water phase linear categories. The relationship between different types of relative permeability curves with reservoir characteristics, moisture content, common infiltration points, common permeation range and oil displacement efficiency have been evaluated. Analysis the distribution of the reservoir usable remaining oil and reservoir irreducible oil of different types of relative permeability curves.

Effect of surface roughness and lithology on the water–gas and water–oil relative permeability ratios of oil-wet single fractures

This paper discusses the effect of surface roughness on the water–gas and water–oil relative permeabilities of single fractures. After manufacturing 20×20cm transparent replicas of fractures developed under tensional load, constant injection rate displacement experiments were performed. Saturation distribution against time was visually monitored and the residual phases were determined for seven fracture samples of different rock types. These values were then correlated to the fractal and statistical properties of the fracture surfaces. Fractures developed from less porous and larger grain size rock samples (marbles) showed “larger scale” heterogeneity, which caused residual phase saturation in the form of large pockets. Porous rocks with small grain sizes (limestones) showed “small scale” heterogeneity yielding residual saturations in small pockets. The fractal dimension obtained by the triangular prism method has more control on the residual saturation distribution than the other fractal and statistical parameters.Subsequently, the relative permeability ratios were determined using the simplified Corey equation for fracture systems and the conditions causing deviations from the “cubic ratio” behavior were clarified qualitatively and quantitatively for four different displacement cases (water–gas, gas–water, oil–water, and water–oil).In the liquid-liquid cases, the deviations were due to a combined effect of wettability and roughness. Highly granular (and porous) limestone samples, with the smallest grain size out of the seven samples, presented the biggest deviation from the “cubic ratio” in the water displacing oil and gas cases.The semi-quantitative analysis presented in this paper is expected to give new insights into residual phase saturation development and the deviations of relative permeabilities from the traditionally accepted “cubic ratio” behavior.

A new approach to obtaining relative permeability curves during chemical flooding process in a low-permeable reservoir

It is always difficult to obtain the relative permeability curve for a low-permeable reservoir using chemical flooding, as there are so many problems associated with the current measurement methods, especially when interfacial tension σ, wettability cosθ and pore–throat radius ratio m are considered as the main factors that influence the shape of the relative permeability curve, and thereby the oil recovery. This paper presents a new concept of modified capillary numbers (N CM), associated with these three factors. First, laboratory experiments were carried out to get relationship between N CM and the residual oil saturation S OR under different conditions. Second, oil–water relative permeability curves for a target oil layer using the steady-state flow method were determined. Using these two steps, a relative permeability curve under different conditions of interfacial tension σ, wettability cosθ and pore–throat radius ratio m has been drawn. Based on the calculated relative permeability curves, the oil displacement efficiency and flow capacity were determined. Subsequently, the relationships between the relative permeability curve, oil displacement efficiency, flow capacity and the factors for a low-permeable reservoir were established using chemical flooding.

Analytical Estimation of Water-Oil Relative Permeabilities through Fractures

Modeling multiphase flow through fractures is a key issue for understanding flow mechanism and performance prediction of fractured petroleum reservoirs, geothermal reservoirs, underground aquifers and carbon-dioxide sequestration. One of the most challenging subjects in modeling of fractured petroleum reservoirs is quantifying fluids competition for flow in fracture network (relative permeability curves). Unfortunately, there is no standard technique for experimental measurement of relative permeabilities through fractures and the existing methods are very expensive, time consuming and erroneous. Although, several formulations were presented to calculate fracture relative permeability curves in the form of linear and power functions of flowing fluids saturation, it is still unclear what form of relative permeability curves must be used for proper modeling of flow through fractures and consequently accurate reservoir simulation. Basically, the classic linear relative permeability (X-type) curves are used in almost all of reservoir simulators. In this work, basic fluid flow equations are combined to develop a new simple analytical model for water-oil two phase flow in a single fracture. The model gives rise to simple analytic formulations for fracture relative permeabilities. The model explicitly proves that water-oil relative permeabilities in fracture network are functions of fluids saturation, viscosity ratio, fluids density, inclination of fracture plane from horizon, pressure gradient along fracture and rock matrix wettability, however they were considered to be only functions of saturations in the classic X-type and power (Corey [35] and Honarpour et al. [28, 29]) models. Eventually, validity of the proposed formulations is checked against literature experimental data. The proposed fracture relative permeability functions have several advantages over the existing ones. Firstly, they are explicit functions of the parameters which are known for each of simulation computational cells or easy to measure in laboratory. It is also the first model that takes gravity effects and wettability of fracture walls into consideration and individually developed for water and oil-wet systems. Furthermore, the newly developed formulations are simple, efficient and accurate. Thus, they are recommended for implementation in dual and multiple continuum commercial reservoir simulators.

Monitoring the influence of dispersed nano-particles on oil–water relative permeability hysteresis

In recent years, polysilicon nanoparticles are used to enhance the oil recovery through the water injection process in oilfields. The contributing mechanisms are the reduction of interfacial tension and wettability alteration which lead to improving or decreasing the oil phase relative permeability and can be traced by change of relative permeability curves. However, profound understanding of the effect of dispersed nano-silica particles on the hysteretic behavior of relative permeability curves remains a controversy topic in the literature. The current study illustrates the influence of dispersed silica particles on hysteretic trend of two-phase curves of oil–water relative permeability. Displacement tests of light crude oil by water as well as water dispersed Nano-silica particles were performed on a sandstone rock sample, and the relative permeability curves of oil and water phases were considered for two successive cycles of imbibition and drainage processes. Primarily, the results revealed that the degree of hysteresis in two phase relative permeability decreased as the dispersed nano-silica particles were used in the tests; besides the hysteretic behavior of relative permeability curves decreased as the injection proceeded into its second cycle. Moreover, the relative permeability of non-wetting phase changed significantly while the changes for wetting phase did not appear quite considerable. The results of this work can help with finding an appropriate relative permeability curves during EOR processes in case of changing the direction of displacement. • The influence of dispersed silica particles on hysteretic trend of two-phase curves of oil–water relative permeability. • Finding the dominant mechanism of EOR during nanofluid injection processes. • Experimental unsteady state displacement tests of water/water saturated by dispersed nanoparticles-light crude oil systems.

The Prediction of Water-oil Relative Permeability Key Points Using An Adaptive Neuro-fuzzy Inference System

Adaptive neuro-fuzzy inference system (ANFIS) is a powerful nonlinear, multivariable regression technique. Here ANFIS was used to identify complex relation between water-oil relative permeability key points and rock and fluid properties. Some 260 relative permeability curves from Iranian carbonate and sandstone reservoirs were used in this study. For each curve six key points (i.e., end points and the crossover points) were considered. ANFIS was then used to predict these key points from different rock and fluid properties. The results showed that very high correlation coefficients in the range of 0.8–0.92 are achievable for Kr key points. ANFIS is a very suitable tool therefore to obtain un-normalized water-oil relative permeability curves with high accuracy when the required core and fluid properties are available.

Characterisation of water-oil drainage process through a reservoir rock sample by digital core analysis

Oil-water relative permeability and capillary pressure of a water-wet digital core are computed using the finite-volume/volume of fluid method and mimicking traditional laboratory steady-state experiments carried out on a water saturated sample. Commercial software is used for immiscible multiphase fluid flow simulations, carried out on a low-cost multicore workstation, and the porescale data are upscaled to derive relative permeability and capillary pressure curves as function of water saturation. The digital sample is obtained by high resolution X-ray computed tomography scanning.