Wettability Determination and Its Effect on Recovery Efficiency

1969 ◽  
Vol 9 (01) ◽  
pp. 13-20 ◽  
Author(s):  
Erle C. Donaldson ◽  
Rex D. Thomas ◽  
Philip B. Lorenz
Keyword(s):  
Crude Oil ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Quantitative Method ◽  
Test Procedure ◽  
Dye Adsorption ◽  
Pressure Curve ◽  
Recovery Efficiency ◽  
Water Drainage ◽  
Capillary Pressure Curves

Abstract A quantitative method for measuring the wettability of porous media containing brine and crude oil has been developed by the USBM using capillary pressure curves determined with a centrifuge. These measurements were reproducible within a standard deviation of 8.2 percent. The determination of fractional wettability has been compared with a method involving a combination of imbibition and displacement. Results are in agreement qualitatively as to whether a sample was water-wet or oil-wet. When tested with outcrop cores of Torpedo Sandstone, wetting tendencies of oils from widely different fields range from highly water-wet to almost neutral. Silicone-treated cores vary in extent of wettability in a predictable manner, becoming more oil-wet as the concentration of silicone used in core preparation is increased. Wettability, used as a parameter in designing linear mathematical models for predicting recovery efficiency, is equal in significance to viscosity and permeability. permeability Introduction Wettability is one of the major factors that influences oil recovery. The importance of maintaining a water-wet condition in a field under water drive has been discussed by many authors. These authors have shown that oil recovery, as a function of the water injected, is greater from water-wet cores than from oil-wet cores. A few authors have indicated that recovery from strongly water-wet or oil-wet cores is less than recovery from cores that are at some intermediate wettability. One reason that the significance of wettability to oil recovery is still being evaluated is because a quantitative measurement of wettability has not been available when crude oil is involved. Some qualitative methods for determining the wettability of cores that are discussed in the literature includeuse of relative permeability data,imbibition,displacement pressure,capillary pressure, anda combination of imbibition and displacement. Using these methods, cores can be classified as either water-wet or oil-wet. However, these methods are not satisfactory for intermediate wettabilities between water-wet and oil-wet. Nuclear magnetic relaxation and dye adsorption offer promise of a quantitative method for determining wettability; however, they have not been widely accepted. This paper presents a quantitative technique for determining the wettability of sandstone cores containing brine and crude petroleum oils. The method is rapid and reproducible and requires only a minimum handling of the cores before testing. It also establishes a numerical wettability scale for systems ranging from strongly water-wet to strongly oil-wet. TECHNIQUE WETTABILITY TEST PROCEDURE The USBM method for determining wettability is based on a correlation, suggested by Gatenby and Marsden, between the degree of wetting and the areas under the capillary-pressure curves. The method employs the two areas under the capillary-pressure curves obtained by the centrifuge method described by Slobod et al., and extended to determine capillary pressure curves for oil and water. Gatenby and Marsden, and earlier Slobod and Blum, suggested the use of individual points on the capillary pressure curve, but the area is considered representative of the over-all wettability, as it is an integrated value over the practical range of saturations. Capillary-pressure curves obtained by the centrifugal method are not complete descriptions of the capillary pressure vs saturation relationship of a porous medium. The water imbibition curve for pressures greater than zero and the water drainage curve for pressures less than zero cannot be obtained by the centrifugal technique. SPEJ P. 13

Pore-Scale Modeling of Wettability Effects and Their Influence on Oil Recovery

1999 ◽  
Vol 2 (01) ◽  
pp. 25-36 ◽  
Author(s):  
A.B. Dixit ◽  
S.R. McDougall ◽  
K.S. Sorbie ◽  
J.S. Buckley
Keyword(s):  
Crude Oil ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Aging Process ◽  
Water Saturation ◽  
Contact Angles ◽  
Initial Water ◽  
Water Imbibition ◽  
Pore Level ◽  
Capillary Pressure Curves

Summary The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters (e.g., Pc and krw/kro) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the "target" oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted (mixed and fractionally wet) systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive—i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general "regime based" theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil- and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed. Introduction In crude oil/brine/rock (COBR) systems, pore level displacements of oil and brine and hence the corresponding petrophysical flow parameters (e.g., Pc and krw/kro) describing these displacements are governed by the pore geometry, topology and wettability of the system. A number of excellent review papers are available that describe experimental investigations of the effect of wettability on capillary pressure and oil-water relative permeability curves.1–5 In COBR systems, wettability alterations depend upon the mineralogical composition of the rock, pH and/or composition of the brine, crude oil composition, initial water saturation, reservoir temperature, etc.6–12 Therefore, in recent years, interest in restoring the wettability of reservoir core using crude oil and formation brine has greatly increased.3,4,13,14 In this approach, cleaned reservoir core is first saturated with brine and then oil flooded to initial water saturation using crude oil. The core containing crude oil and brine is then aged to alter its wettability state. Wettability measurements, such as Amott and USBM tests, and waterflood experiments are then typically conducted on the aged core. This entire process broadly mimics the actual flow sequences in the reservoir; consequently, the wettability alterations are more realistic than those achieved using chemical treatment methods. During the aging process, wettability may be altered to vastly different degrees depending upon many factors, including those mentioned above. In addition, aging time, thickness of existing water films and wetting film disjoining pressure isotherms also play important roles. Hence, the final wettability state of a re-conditioned core will generally be case specific.

scholarly journals Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs

2001 ◽  
Vol 4 (06) ◽  
pp. 455-466 ◽  
Author(s):  
A. Graue ◽  
T. Bognø ◽  
B.A. Baldwin ◽  
E.A. Spinler
Keyword(s):  
Crude Oil ◽  
Numerical Simulations ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
History Matching ◽  
Water Saturation ◽  
Fracture Network ◽  
Stock Tank ◽  
Recovery Mechanisms

Summary Iterative comparison between experimental work and numerical simulations has been used to predict oil-recovery mechanisms in fractured chalk as a function of wettability. Selective and reproducible alteration of wettability by aging in crude oil at an elevated temperature produced chalk blocks that were strongly water-wet and moderately water-wet, but with identical mineralogy and pore geometry. Large scale, nuclear-tracer, 2D-imaging experiments monitored the waterflooding of these blocks of chalk, first whole, then fractured. This data provided in-situ fluid saturations for validating numerical simulations and evaluating capillary pressure- and relative permeability-input data used in the simulations. Capillary pressure and relative permeabilities at each wettability condition were measured experimentally and used as input for the simulations. Optimization of either Pc-data or kr-curves gave indications of the validity of these input data. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations than matching production profiles only. Introduction Laboratory waterflood experiments, with larger blocks of fractured chalk where the advancing waterfront has been imaged by a nuclear tracer technique, showed that changing the wettability conditions from strongly water-wet to moderately water-wet had minor impact on the the oil-production profiles.1–3 The in-situ saturation development, however, was significantly different, indicating differences in oil-recovery mechanisms.4 The main objective for the current experiments was to determine the oil-recovery mechanisms at different wettability conditions. We have reported earlier on a technique that reproducibly alters wettability in outcrop chalk by aging the rock material in stock-tank crude oil at an elevated temperature for a selected period of time.5 After applying this aging technique to several blocks of chalk, we imaged waterfloods on blocks of outcrop chalk at different wettability conditions, first as a whole block, then when the blocks were fractured and reassembled. Earlier work reported experiments using an embedded fracture network,4,6,7 while this work also studied an interconnected fracture network. A secondary objective of these experiments was to validate a full-field numerical simulator for prediction of the oil production and the in-situ saturation dynamics for the waterfloods. In this process, the validity of the experimentally measured capillary pressure and relative permeability data, used as input for the simulator, has been tested at strongly water-wet and moderately water-wet conditions. Optimization of either Pc data or kr curves for the chalk matrix in the numerical simulations of the whole blocks at different wettabilities gave indications of the data's validity. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations of the fractured blocks, in which only the fracture representation was a variable. Experimental Rock Material and Preparation. Two chalk blocks, CHP8 and CHP9, approximately 20×12×5 cm thick, were obtained from large pieces of Rørdal outcrop chalk from the Portland quarry near Ålborg, Denmark. The blocks were cut to size with a band saw and used without cleaning. Local air permeability was measured at each intersection of a 1×1-cm grid on both sides of the blocks with a minipermeameter. The measurements indicated homogeneous blocks on a centimeter scale. This chalk material had never been contacted by oil and was strongly water-wet. The blocks were dried in a 90°C oven for 3 days. End pieces were mounted on each block, and the whole assembly was epoxy coated. Each end piece contained three fittings so that entering and exiting fluids were evenly distributed with respect to height. The blocks were vacuum evacuated and saturated with brine containing 5 wt% NaCl+3.8 wt% CaCl2. Fluid data are found in Table 1. Porosity was determined from weight measurements, and the permeability was measured across the epoxy-coated blocks, at 2×10–3 µm2 and 4×10–3 µm2, for CHP8 and CHP9, respectively (see block data in Table 2). Immobile water saturations of 27 to 35% pore volume (PV) were established for both blocks by oilflooding. To obtain uniform initial water saturation, Swi, oil was injected alternately at both ends. Oilfloods of the epoxy-coated block, CHP8, were carried out with stock-tank crude oil in a heated pressure vessel at 90°C with a maximum differential pressure of 135 kPa/cm. CHP9 was oilflooded with decane at room temperature. Wettability Alteration. Selective and reproducible alteration of wettability, by aging in crude oil at elevated temperatures, produced a moderately water-wet chalk block, CHP8, with similar mineralogy and pore geometry to the untreated strongly water-wet chalk block CHP9. Block CHP8 was aged in crude oil at 90°C for 83 days at an immobile water saturation of 28% PV. A North Sea crude oil, filtered at 90°C through a chalk core, was used to oilflood the block and to determine the aging process. Two twin samples drilled from the same chunk of chalk as the cut block were treated similar to the block. An Amott-Harvey test was performed on these samples to indicate the wettability conditions after aging.8 After the waterfloods were terminated, four core plugs were drilled out of each block, and wettability measurements were conducted with the Amott-Harvey test. Because of possible wax problems with the North Sea crude oil used for aging, decane was used as the oil phase during the waterfloods, which were performed at room temperature. After the aging was completed for CHP8, the crude oil was flushed out with decahydronaphthalene (decalin), which again was flushed out with n-decane, all at 90°C. Decalin was used as a buffer between the decane and the crude oil to avoid asphalthene precipitation, which may occur when decane contacts the crude oil.

Characterization of Fluid Drainage Mechanism at Core and Pore Scales: an NMR Capillary Pressure–Based Saturation Exponent Prediction

2021 ◽  
Author(s):  
Abubakar Isah ◽  
Abdulrauf Rasheed Adebayo ◽  
Mohamed Mahmoud ◽  
Lamidi O. Babalola ◽  
Ammar El-Husseiny
Keyword(s):  
Electrical Resistivity ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Gas Storage ◽  
Pressure Curve ◽  
Pore Scale ◽  
Resistivity Index ◽  
Capillary Pressure Curve ◽  
In Series ◽  
Saturation Exponent

Abstract Capillary pressure (Pc) and electrical resistivity index (RI) curves are used in many reservoir engineering applications. Drainage capillary pressure curve represents a scenario where a non-wetting phase displaces a wetting phase such as (i) during gas injection (ii) gas storage in reservoirs (e.g. aquifer or depleted hydrocarbon reservoirs). The gas used for injection is typically natural gas, N2, or CO2. Gas storage principally used to meet requirement variations, and water injection into oil-wet reservoirs are drainage processes. Resistivity index (RI) curve which is used to evaluate the potential of oil recovery from a reservoir, is also an important tool used in log calibration and reservoir fluid typing. The pore drainage mechanism in a multimodal pore system is important for effective recovery of hydrocarbon reserves; enhance oil recovery (EOR) planning and underground gas storage. The understanding of pore structure and drainage mechanism within a multimodal pore system during petrophysical analysis is of paramount importance to reservoir engineers. Therefore, it becomes inherent to study and establish a way to relate these special core analyses laboratory (SCAL) methods with quick measurements such as the nuclear magnetic resonance (NMR) to reduce the time requirement for analysis. This research employed the use of nuclear magnetic resonance (NMR) to estimate saturation exponent (n) of rocks using nitrogen as the displacing fluid. Different rock types were used in this study that cover carbonates, sandstones, and dolomites. We developed an analytical workflow to separate the capillary pressure curve into capillary pressure curve for macropores and a capillary pressure curve for the micropores, and then used these pore scale Pc curves to estimate an NMR - capillary pressure - based electrical resistivity index - saturation (NMR-RI-Sw) curve for the rocks. We predicted the saturation exponent (n) for the rock samples from the NMR-RI-Sw curve. The NMR-based saturation exponent estimation method requires the transverse (T2) relaxation distribution of the rock - fluid system at various saturations. To verify the reliability of the new workflow, we performed porous plate capillary pressure and electrical resistivity measurements on the rock samples. The reliability of the results for the resistivity index curve and the saturation exponent was verified using the experimental data obtained from the SCAL method. The pore scale Pc curve was used to ascertain the drainage pattern and fluid contribution of the different pore subsystems. For bimodal rock system, the drainage mechanism can be in series, in parallel, or in series - parallel depending on the rock pore structure.

Experimental Validation of a Pore-Scale-Derived Dimensionless Capillary Pressure Function for Imbibition Under Mixed-Wet Conditions

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1338-1348 ◽  
Author(s):  
Y.. Zhou ◽  
J. O. Helland ◽  
D. G. Hatzignatiou ◽  
R.. Ahsan ◽  
A.. Hiorth
Keyword(s):  
Capillary Pressure ◽  
Reservoir Simulation ◽  
Simulation Models ◽  
Pressure Curve ◽  
Pore Scale ◽  
Pressure Function ◽  
Capillary Pressure Curve ◽  
Mixed Wettability ◽  
Dimensionless Function ◽  
Capillary Pressure Curves

Summary We validate experimentally a dimensionless capillary pressure function for imbibition at mixed-wet conditions that we developed recently on the basis of pore-scale modeling in rock images. The difference from Leverett's traditional J-function is that our dimensionless function accounts for wettability and initial water saturation after primary drainage through area-averaged, effective contact angles that depend on the wetting property and distribution of oil- and water-wet grain surfaces. In the present work, we adopt the dimensionless function to scale imbibition capillary pressure data measured on mixed-wet sandstone and chalk cores. The measured data practically collapse to a unique curve when subjected to the dimensionless capillary pressure function. For each rock material, we use the average dimensionless curve to reproduce the measured capillary pressure curves and obtain excellent agreement. We also demonstrate two approaches to generate different capillary pressure curves at other mixed-wettability states than that available from the data used to generate the dimensionless curve. The first approach changes the shape of the spontaneous- and forced-imbibition segments of the capillary pressure curve whereas the saturation at zero capillary pressure is constant. The second approach shifts the vertical level of the entire capillary pressure curve, such that the Amott wetting index (and the saturation at zero capillary pressure) changes accordingly. Thus, integrating these two approaches with the dimensionless function yields increased flexibility to account for different mixed-wettability states. The validated dimensionless function scales mixed-wet capillary pressure curves from core samples accurately, which demonstrates its applicability to describe variations of wettability and permeability with capillary pressure in reservoir-simulation models. This allows for improved use of core experiments in predicting reservoir performance. Reservoir-simulation models can also use the dimensionless function together with existing capillary pressure correlations.

A Pore-Network-Modeling Approach To Predict Petrophysical Properties of Diatomaceous Reservoir Rock

2007 ◽  
Vol 10 (06) ◽  
pp. 597-608 ◽  
Author(s):  
Liping Jia ◽  
Cynthia Marie Ross ◽  
Anthony Robert Kovscek
Keyword(s):  
Multiphase Flow ◽  
Capillary Pressure ◽  
Network Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Pore Network ◽  
Reservoir Rock ◽  
Pore Network Model ◽  
Rock Types ◽  
Capillary Pressure Curves

Summary A 3D pore-network model of two-phase flow was developed to compute permeability, relative permeability, and capillary pressure curves from pore-type, -size, and -shape information measured by means of high-resolution image analysis of diatomaceous-reservoir-rock samples. The diatomite model is constructed using pore-type proportions obtained from image analysis of epoxy-impregnated polished samples and mercury-injection capillary pressure curves for diatomite cores. Multiple pore types are measured, and each pore type has a unique pore-size and throat-size distribution that is incorporated in the model. Network results present acceptable agreement when compared to experimental measurements of relative permeability. The pore-network model is applicable to both drainage and imbibition within diatomaceous reservoir rock. Correlation of network-model results to well log data is discussed, thereby interpolating limited experimental results across the entire reservoir column. Importantly, our method has potential to predict the petrophysical properties for reservoir rocks with either limited core material or those for which conventional experimental measurements are difficult, unsuitable, or expensive. Introduction Model generation for reservoir simulation requires accurate entering of physical properties such as porosity, permeability, initial water saturation, residual-oil saturation, capillary pressure functions, and relative permeability curves. These functions and parameters are necessary to estimate production rate and ultimate oil recovery, and thereby optimize reservoir development. Accurate measurement and representation of such information is, therefore, essential for reservoir modeling. Relative permeability and capillary pressure curves are the most important constitutive relations to represent multiphase flow. Often, it is difficult to sample experimentally the range of relevant multiphase-flow behavior of a reservoir. In addition to the availability of rock samples, measurements are frequently time consuming to conduct, and conventional techniques are not suitable for all rock types (Schembre and Kovscek 2003). It is impossible, therefore, to measure all the unique relative permeability functions of different reservoir-rock types and variations within a rock type. This lack of constitutive information limits the accuracy of reservoir simulators to predict oil recovery. Simply put, other available data must be queried for their relevance to multiphase flow and must be used to interpret the available relative permeability and capillary pressure information.

Investigation of Reduced Interfacial Tension by Surfactant Flooding in Mixed-Wet Reservoirs

2021 ◽  
Author(s):  
Usman Aslam
Keyword(s):  
Interfacial Tension ◽  
Capillary Pressure ◽  
Enhanced Oil Recovery ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Simulation Studies ◽  
Surfactant Flooding ◽  
Gravity Segregation ◽  
Simulation Results ◽  
Capillary Pressure Curves

Abstract Surfactant flooding has long been considered a reliable solution for enhanced oil recovery, either by reducing oil-water interfacial tension (IFT) or through wettability alteration. This paper reveals the effect that reduced IFT has on capillary trapping in heterogeneous reservoirs. This effect is investigated through various numerical experiments on different simulation models where rock capillary pressure is assumed to scale with IFT. Capillary contrast on the scale of a few centimeters to a few tens of meters is reduced in the presence of surfactants. This reduction in IFT, under very specific circumstances, creates favorable conditions for increased or accelerated hydrocarbon production from mixed-wet reservoirs. The focus of this study is to ascertain the effectiveness of surfactant flooding in mixed-wet reservoirs. Simulation studies of different mechanisms which are believed to occur in mixed-wet reservoirs are presented. Simulation results indicate the promising effect of surfactant flooding on oil recovery, depending on the type of reservoir. Detailed fine-scale simulation studies are carried out with representative relative permeability and imbibition capillary pressure curves from mixed-wet cores. By designing and selecting a series of surfactants to lower the IFT to the range of 10-3dynes/cm, a recovery of 10 to 20% of the original oil-in-place is technically and economically feasible. The efficiency of surfactant flooding is investigated through sensitivity scenarios on formation rock/fluid parameters, including permeability, interfacial tension, rate flow, etc. Geological heterogeneity (layering and heterogeneous inclusions), imbibition capillary pressure curves, viscous/capillary balance (Nc), and gravitational forces were all found to have an impact on recovery by surfactant flooding. Numerical model dimensions, permeability, IFT, density contrast between oil and water, and injection flow rates were found to be the critical parameters influencing simulation results. Gravity segregation, typically ignored in earlier studies, was found to have a significant effect on reservoir performance. Two different numerical models, with and without impermeable shale streaks, were used to capture the gravity segregation effect. The results revealed that the reduction in interfacial tension helps gravity to segregate oil and water, ultimately resulting in improved oil recovery. Moreover, results from the numerical simulation studies revealed that either an inexpensive or a good quality surfactant at low concentration can be used to obtain the same enhanced oil recovery. The effect of change in oil relative permeability curvature, due to reduced interfacial tension, also revealed a reduction in the remaining oil saturation with an increase in the capillary number.

Capillary-Pressure Curves for Low-Permeability Chalk Obtained by Nuclear Magnetic Resonance Imaging of Core-Saturation Profiles

1999 ◽  
Vol 2 (02) ◽  
pp. 141-148 ◽  
Author(s):  
J.V. Nørgaard ◽  
Dan Olsen ◽  
Jan Reffstrup ◽  
Niels Springer
Keyword(s):  
Steady State ◽  
Capillary Pressure ◽  
Porous Plate ◽  
Low Permeability ◽  
Pressure Curve ◽  
Centrifuge Method ◽  
The Core ◽  
Fluid Saturation ◽  
Capillary Pressure Curves ◽  
Saturation Profile

Summary A new technique for obtaining water-oil capillary pressure curves, based on nuclear magnetic resonance (NMR) imaging of the saturation distribution in flooded cores is presented. In this technique, a steady-state fluid saturation profile is developed by flooding the core at a constant flow rate. At the steady-state situation where the saturation distribution no longer changes, the local pressure difference between the wetting and nonwetting phases represents the capillary pressure. The saturation profile is measured using an NMR technique and for a drainage case, the pressure in the nonwetting phase is calculated numerically. This paper presents the NMR technique and the procedure for calculating the pressure distribution in the sample. Inhomogeneous samples produce irregular saturation profiles, which may be interpreted in terms of variation in permeability, porosity, and capillary pressure. Capillary pressure curves for North Sea chalk obtained by the new technique show good agreement with capillary pressure curves obtained by traditional techniques. Introduction Accurate petrophysical properties of reservoir rock such as capillary pressure, permeability, and relative permeability functions are essential as input for reliable oil in place estimations and for the prediction of the reservoir performance. Traditional methods for capillary pressure measurements are the mercury injection method, the diaphragm method, and the centrifuge method. In the mercury injection method,1 the nonwetting phase is mercury which displaces a gas. The samples are usually evacuated to a low pressure and Hg is then injected in steps allowing for pressure equilibrium at each step, or alternatively Hg is continuously injected. Corresponding data on injected volume of Hg and the injection pressure are recorded. This technique is widely used for measuring capillary pressure functions for low permeability rocks. This is primarily because it is generally believed that pressure equilibrium in each pressure step is readily obtained, while this is normally a problem for other methods where a liquid is the wetting phase. The disadvantage of this technique is the uncertainty in the scaling of the measured data to reservoir fluid data and conditions. In the diaphragm method or porous plate method, the problem concerning the scaling of the measured data is avoided, since this technique allows for the direct use of reservoir fluids. A water saturated sample is placed on a water-wet diaphragm to impose a boundary condition pc=0 to the wetting phase, i.e., the wetting phase is allowed to drain through the outlet end of the sample, at the same time as the nonwetting phase (oil or gas) is impeded. Pressure is added to the nonwetting phase and through a limited number of pressure steps, the capillary pressure curve is recorded. However, an important requirement is that equilibrium is obtained at each pressure step. This is the major problem when the diaphragm method is used on microporous materials. The drainage time may be considerable for each step, e.g., several weeks. In recent studies, thin micropore membranes have been used in an attempt to reduce the experimental time.2 Such a reduction will be less pronounced for low permeability rocks such as chalk since the flow resistance in the core is relatively more important. In the centrifuge method, the amount of liquid produced from the outlet end of the plug sample at a certain spin rate is read directly from a measuring tube during rotation. From the geometry of the centrifuge, the spin rate and the average fluid saturation in the plug, it is possible to calculate the capillary pressure relative to the inlet end of the sample.3 However, a number of assumptions must be made3,4: the sample must be homogeneous and have a well-defined outlet pressure boundary condition, i.e., condition pc=0, and drainage equilibrium must be established at each spin rate. Most of these conditions can only be approximated in practice. For the centrifuge method, the condition of drainage equilibrium may be questionable even for sandstone samples.5 Slobod6 reported that equilibrium had not been attained for a 2 mD sample after 20 hr of spinning. King7 concluded that low permeability rock samples may suffer from very long equilibrium times. After 10 days of spinning in the centrifuge, a Berea sandstone sample of 200 mD had just reached equilibrium. The objective of the development of the method presented here has been to avoid some of the disadvantages of the conventional methods described above. In this method a capillary pressure curve is obtained from a measured saturation profile after flooding the core. A similar experimental procedure was used by Richardson et al.8 to study end effects associated with flooding processes. The technique described here can be used with reservoir fluids. There is no porous plate to increase the flow resistance and the measurement of the capillary pressure function can be an integrated part of traditional flooding processes as performed with, e.g., unsteady-state relative permeability measurements. Only a very limited number of steps are needed, in principle only one step is required, therefore the time requirement for obtaining drainage equilibrium has not proved to be a problem. The technique utilizes the unavoidable end effect present in experiments with low permeability rocks. The capillary pressure function is obtained from the steady-state saturation profile in the core at drainage equilibrium.

Effect of Nickel: Zinc Ratio in Nickel-Zinc-Ferrite Nanoparticles as Surfactant on Recovery Efficiency in Enhanced Oil Recovery

2014 ◽  
Vol 29 ◽  
pp. 115-120 ◽  
Author(s):  
Hasnah Mohd Zaid ◽  
W.A. Wan Azahar ◽  
H. Soleimani ◽  
N.R. Ahmad Latiff ◽  
Afza Shafie ◽  
...  
Keyword(s):  
Magnetic Nanoparticles ◽  
Crude Oil ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Zinc Ferrite ◽  
Bulk Material ◽  
Recovery Efficiency ◽  
X Ray Diffraction ◽  
Nickel Zinc ◽  
A Chain

Integration of nanoparticles in enhanced oil recovery (EOR) has been intensively studied in recent years due to their unique properties owing to the nanoscale dimensions, rendering them to have different properties in comparison with its bulk material. Application of magnetic nanoparticles such as ferrites was able to exploit their rheological properties as a chain-like structure formed due to dipole-dipole alignment with the applied magnetic field. Ferromagnetic nanoparticles had shown an increment in the oil recovery under the irradiation of an EM wave. In this research, the influence of magnetic nanoparticles nickel-zinc-ferrite, Ni1-xZnxFe2O2 in the form of nanofluids on the recovery efficiency in EOR was studied. Nickel-zinc-ferrite magnetic nanoparticles with various values of x were synthesized to observe the effect of nickel to zinc ratio on recovery efficiency. The nanoparticles were characterized using X-ray Diffraction (XRD) and Vibrating Sample Magnetometer (VSM). Coreflooding experiments were conducted where the nanofluids were injected into the compacted sand saturated with crude oil under EM irradiation. The amount of oil recovered from the core was evaluated. VSM tests shows that the sample with x = 0.5 had the highest magnetization of 52.6 emu/g. The nanofluids prepared from the sample also achieved the highest crude oil recovery of 26.07% of the residual oil in place (ROIP).

In-Situ Phase Pressures and Fluid Saturation Dynamics Measured in Waterfloods at Various Wettability Conditions

2010 ◽  
Vol 13 (03) ◽  
pp. 465-472 ◽  
Author(s):  
Amund Brautaset ◽  
Geir Ersland ◽  
Arne Graue
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Spontaneous Imbibition ◽  
Flow In Porous Media ◽  
Relative Permeabilities ◽  
Dynamic Capillary Pressure ◽  
Fluid Saturation ◽  
Local Recovery ◽  
Capillary Pressure Curves

Summary During waterfloods of six outcrop chalk core-plug samples prepared at various wettabilities, simultaneous local pressures and in-situ fluid saturations were measured. Using high-spatial-resolution magnetic-resonance imaging (MRI) to image fluid saturations and pressure taps with semipermeable disks to measure individual phase pressures allowed calculations of relative permeabilities and the dynamic capillary pressure curves for the imbibition processes. A second objective was to identify individual-fluid saturation changes caused by spontaneous imbibition and viscous displacement to determine the local recovery mechanism and to calculate local recovery factors and in-situ Amott-Harvey indices. The obtained results contribute to improved description and understanding of multiphase-fluid flow in porous media, including in situ measurements of relative permeabilities, dynamic capillary pressure curves, Amott-Harvey Indices, and local oil-recovery mechanisms.

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