scholarly journals Relationships among air-water interfacial area, capillary pressure, and water saturation for a sandy porous medium

2006 ◽  
Vol 42 (3) ◽  
Author(s):  
Mark L. Brusseau ◽  
Sheng Peng ◽  
Gregory Schnaar ◽  
Molly S. Costanza-Robinson
Keyword(s):  
Porous Medium ◽  
Capillary Pressure ◽  
Water Saturation ◽  
Interfacial Area

Calculation of Oil Displacement by Countercurrent Water Imbibition

1964 ◽  
Vol 4 (03) ◽  
pp. 195-202 ◽  
Author(s):  
P.M. Blair
Keyword(s):  
Porous Medium ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Water Saturation ◽  
Pressure Gradients ◽  
Oil Viscosity ◽  
Initial Water ◽  
Water Imbibition ◽  
Pressure Profiles ◽  
Water Viscosity

Abstract This paper presents numerical solutions of the equations describing the imbibition of water and the countercurrent flow of oil in porous rocks. The imbibition process is of practical importance in recovering oil from heterogeneous formations and has been studied principally by experimental means. Calculations were made for imbibition of water into both linear and radial systems. Imbibition in the linear systems was allowed to take place through one open, or permeable, face of the porous medium studied. In the radial system, water was imbibed inward from the outer radius. The effects on rate of imbibition of varying the capillary pressure and relative permeability curves, oil viscosity and the initial water saturation were computed. For each case studied, the rate of water imbibition and the saturation and pressure profiles were calculated as functions of time. The results of these calculations indicate that, for the porous medium studied, the time required to imbibe a fixed volume of water of a certain viscosity is approximately proportional to the square root of the viscosity of the reservoir oil whenever the oil viscosity is greater than the water viscosity. Results are also presented illustrating the effects on rate of imbibition of the other variables studied. Introduction The process of imbibition, or spontaneous flow of fluids in porous media under the influence of capillary pressure gradient s, occurs wherever there exist in permeable rock capillary pressure gradients which are not exactly balanced by opposing pressure gradients (such as those resulting from the influence of gravity). The importance of such capillary movement in the displacement of oil by water or gas was recognized in early investigations and described by Leverett, Lewis and True in 1942. Methods advanced by these authors for studying the process using dynamically scaled models were rendered more general and flexible by the research of later workers. The influence of capillary forces in laboratory water floods has also been discussed by several authors. While imbibition plays a very important role in the recovery of oil from normal reservoirs, Brownscombe and Dyes pointed out that imbibition might be the dominant displacement process in water flooding reservoirs characterized by drastic variations in permeability, such as in fractured- matrix reservoirs. In water-wet, fractured-matrix reservoirs, water will be imbibed from fractures into the matrix with a countercurrent expulsion of oil into the fractures. If the imbibition occurs at a sufficiently rapid rate, a very successful water flood can result; if the imbibition proceeds slowly the project might not be economically attractive. Scaled-model studies have demonstrated the vital importance of imbibition in secondary recovery in fractured reservoirs. It is therefore important in the evaluation of waterflooding prospects to develop a thorough understanding of the quantitative relationships of the factors which control the rapidity of capillary imbibition. The imbibition process serves reservoir engineers in still another important way by providing a technique for studying the wettability of reservoir core samples. Such experiments are usually conducted by observing the rate of expulsion of oil or water from core samples submerged in the appropriate fluid. Several papers have been published on the experimental techniques involved. Although Handy has recently published a method for calculating capillary pressures from experiments with gas-saturated cores, it has not yet been possible to deduce quantitative information regarding water-oil relative permeability and capillary pressure characteristics of the rock from the experimental results. Thus a technique is needed for studying the quantitative dependence of imbibition rate on oil and water viscosity, initial water saturation, relative permeability-saturation, and capillary pressure-saturation relations. The development of such information, including saturation and pressure profiles by laboratory experiments, would be very difficult. SPEJ P. 195ˆ

The model of capillary pressure and water saturation dependence taking into account displacement pressure

2018 ◽  
pp. 38-42
Author(s):  
K.V. Kovalenko ◽  
◽  
M.S. Khokhlova ◽  
A.N. Petrov ◽  
N.I. Samokhvalov ◽  
...  
Keyword(s):  
Capillary Pressure ◽  
Water Saturation

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.

Estimation of the fluid-fluid interfacial area using kinetic interface sensitive tracers in dynamic porous media experiments

2021 ◽  
Author(s):  
Alexandru Tatomir ◽  
Huhao Gao ◽  
Hiwa Abdullah ◽  
Martin Sauter
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Two Phase Flow ◽  
Organic Liquid ◽  
Column Experiment ◽  
Interfacial Area ◽  
Breakthrough Curves ◽  
Water Soluble ◽  
Phase Flow ◽  
Two Phase

<p>Fluid-fluid interfacial area (IFA) in a two-phase flow in porous media is an important parameter for many geoscientific applications involving mass- and energy-transfer processes between the fluid-phases. Schaffer et al. (2013) introduced a new category of reactive tracers termed kinetically interface sensitive (KIS) tracers, able to quantify the size of the fluid-fluid IFA. In our previous experiments (Tatomir et al., 2018) we have demonstrated the application of the KIS tracers in a highly-controlled column experiment filled with a well-characterized porous medium consisting of well-sorted, spherical glass beads.</p><p>In this work we investigate several types of glass-bead materials and natural sands to quantitatively characterize the influence of the porous-medium grain-, pore-size and texture on the mobile interfacial area between an organic liquid and water. The fluid-fluid interfacial area is determined by interpretation of the breakthrough curves (BTCs) of the reaction product of the KIS tracer. When the tracer which is dissolved in the non-wetting phase meets the water, an irreversible hydrolysis process begins leading to the formation of two water-soluble products. For the experiments we use a peristaltic pump and a high precision injection pump to control the injection rate of the organic liquid and tracer.</p><p>A Darcy-scale numerical model is used to simulate the immiscible displacement process coupled with the reactive tracer transport across the fluid-fluid interface. The results show that the current reactive transport model is not always capable to reproduce the breakthrough curves of tracer experiments and that a new theoretical framework may be required.</p><p>Investigations of the role of solid surface area of the grains show that the grain surface roughness has an important influence on the IFA. . Furthermore, a linear relationship between the mobile capillary associated IFA and the inverse mean grain diameter can be established. The results are compared with the data collected from literature measured with high resolution microtomography and partitioning tracer methods. The capillary associated IFA values are consistently smaller because KIS tracers measure the mobile part of the interface. Through this study the applicability range of the KIS tracers is considerably expanded and the confidence in the robustness of the method is improved.</p><p> </p><p> </p><p>Schaffer M, Maier F, Licha T, Sauter M (2013) A new generation of tracers for the characterization of interfacial areas during supercritical carbon dioxide injections into deep saline aquifers: Kinetic interface-sensitive tracers (KIS tracer). International Journal of Greenhouse Gas Control 14:200–208. https://doi.org/10.1016/j.ijggc.2013.01.020</p><p>Tatomir A, Vriendt KD, Zhou D, et al (2018) Kinetic Interface Sensitive Tracers: Experimental Validation in a Two-Phase Flow Column Experiment. A Proof of Concept. Water Resources Research 54:10,223-10,241. https://doi.org/10.1029/2018WR022621</p>

Modeling Two-Phase Flow in Porous Media Including Fluid-Fluid Interfacial Area

2008 ◽  
Author(s):  
Jennifer Niessner ◽  
S. Majid Hassanizadeh ◽  
Dustin Crandall
Keyword(s):  
Porous Media ◽  
Capillary Pressure ◽  
Two Phase Flow ◽  
Interfacial Area ◽  
Flow In Porous Media ◽  
Extended Model ◽  
Phase Flow ◽  
Two Phase ◽  
Specific Interfacial Area ◽  
Macro Scale

We present a new numerical model for macro-scale two-phase flow in porous media which is based on a physically consistent theory of multi-phase flow. The standard approach for modeling the flow of two fluid phases in a porous medium consists of a continuity equation for each phase, an extended form of Darcy’s law as well as constitutive relationships for relative permeability and capillary pressure. This approach is known to have a number of important shortcomings and, in particular, it does not account for the presence and role of fluid–fluid interfaces. An alternative is to use an extended model which is founded on thermodynamic principles and is physically consistent. In addition to the standard equations, the model uses a balance equation for specific interfacial area. The constitutive relationship for capillary pressure involves not only saturation, but also specific interfacial area. We show how parameters can be obtained for the alternative model using experimental data from a new kind of flow cell and present results of a numerical modeling study.

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