Interrelationship of Temperature and Wettability on the Relative Permeability of Heavy Oil in Diatomaceous Rocks (includes associated discussion and reply)

2006 ◽  
Vol 9 (03) ◽  
pp. 239-250 ◽  
Author(s):  
Josephina M. Schembre ◽  
Guo-Qing Tang ◽  
Anthony R. Kovscek
Keyword(s):  
Elevated Temperature ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Heavy Oil ◽  
Thermal Recovery ◽  
Wettability Alteration ◽  
Effect Of Temperature ◽  
Phase Saturation ◽  
Effects Of Temperature ◽  
Relative Permeability Curves

Summary The evaluation of thermal-recovery processes requires relative permeability functions, as well as information about the effects of temperature on these functions. There are significant challenges encountered when estimating relative permeability from laboratory data, such as the accuracy of measurements and generalized assumptions in the interpretation techniques. A novel method is used here to estimate relative permeability and capillary pressure from in-situ aqueous-phase saturation profiles obtained from X-ray computerized tomography (CT) scanning during high-temperature imbibition experiments. Relative permeability and capillary pressure functions are interpreted simultaneously, including possible nonequilibrium effects. Results obtained show a systematic shift toward increased water-wettability with increasing temperature for diatomite reservoir core. The measured changes in relative permeability are linked to the effect of temperature on the adhesion of oil-coated fines to rock surfaces and, ultimately, to rock/fluid interactions. Introduction An understanding of the effects of temperature on wettability and relative permeability functions is essential to optimize and forecast the results of diatomite thermal-recovery projects. Most of the controversy regarding the effect of temperature on relative permeability is caused by the mechanisms involved in rock-wettability change that are dependent on both fluid and rock characteristics. A secondary, and equally important, problem is the technique used to process the data, such as oil recovery, phase saturation, or pressure, as well as data interpretation in the form of relative permeability curves. This paper re-examines the influence of temperature on rock/fluid interactions and heavy-oil relative permeability of diatomite from a core-level experimental and a pore-level perspective. We find experimentally and theoretically that fine particles are released from pore walls under conditions of elevated temperature, high pH, and moderate to low aqueous-phase salinity. The release of fines correlates with changes in relative permeability curves toward greater water-wetness. The mechanism of fines release provides new understanding of a mode of wettability alteration at elevated temperature. This paper is organized as follows. First, a synopsis of the literature is presented, followed by a discussion of recent developments in the understanding of wettability alteration. Second, the experimental method and the relative permeability interpretative methodology are outlined. Third, relative permeability results interpreted from field core samples at temperature are presented. Discussion and conclusions round out the paper.

Displacement Studies in Dolomite With Wettability Control by Octanoic Acid

1973 ◽  
Vol 13 (04) ◽  
pp. 221-232 ◽  
Author(s):  
N.R. Morrow ◽  
P.J. Cram ◽  
F.G. McCaffery
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Significant Influence ◽  
Octanoic Acid ◽  
Contact Angles ◽  
Wettability Alteration ◽  
Residual Oil ◽  
Relative Permeability Curves

Abstract Various nitrogen-, oxygen- and sulfur-containing compounds native to crude oils were screened for their effect on wettability as measured by contact angle. Solid substrates of quartz, calcite, and dolomite crystals were used to represent reservoir rock surfaces. With water and decane as liquids, contact angles were measured after a given polar compound was added to the oil phase. Contact angles measured at the two types of carbonate surfaces were generally similar. None of the nitrogen or sulfur compounds studied gave contact angles greater than 66 degrees on either quartz or carbonates. Of the oxygen-containing compounds, octanoic acid gave the widest range of contact angle - 0 degrees to 145 degrees on dolomite - over a molar concentration range up to 0.1. Capillary - pressure and relative-permeability curves were obtained for water and solutions of octanoic acid in oil, using packings of powdered dolomite as the porous medium. Because of a slow reaction between dolomite and octanoic acid, which was not revealed by standard contact angle studies, special precautions were needed to ensure satisfactory wettability control during displacement tests. Capillary-pressure drainage curves were measured at six contact angles, ranging from 0 degrees to 140 degrees. Drainage-imbibition cycles for three packings of distinctly different particle size were measured at contact angles of 0 degrees and 49 degrees. The effect of contact angle on imbibition capillary pressures was close to that found previously for porous polytetra-fluoroethylene, whereas there was comparatively polytetra-fluoroethylene, whereas there was comparatively less effect on drainage behavior-steady-state relative permeability curves exhibited distinct differences for contact angles of 15 degrees, 100 degrees and 155 degrees. Introduction Waterflooding is the most successful and widely applied improved recovery technique. Its application in Alberta has, on the average, more than doubled the recovery obtained by primary depletion. However, even after waterflooding, it is estimated that two-thirds of the discovered oil remains unrecovered. Interfacial forces acting during waterflooding lead to the entrapment of large quantities of residual oil in the swept zones. Considerable attention has been paid to recovering this oil through new recovery methods in which the interface is eliminated as in miscible processes, or the interfacial tension is drastically lowered, as in surfactant floods. Such processes involve a high initial cost for an injected solvent or surfactant bank. Recently released information on a variety of such improved recovery techniques has not been altogether encouraging with regard to developing economical processes. A distinct alternative to eliminating the interface is to understand it and learn how it can be manipulated to give increased waterflood recoveries. A prospect for improved recovery at interfacial tensions of the order normally encountered in reservoirs lies in a favorable adjustment of wettability by incorporating small amounts of low-cost additives in the floodwater. A first step in developing the technology of improved recovery by wettability alteration is to determine the effect of wettability alteration on displacement in systems of uniform wettability. It has been shown that, even in the "near miscible" surfactant processes, wettability can still have a significant influence on the extent to which interfacial tension must be lowered in order to mobilize residual oil. At the time when waterflooding first found widespread use, wettability was recognized as a variable that might well have a significant influence on recovery performance. Reservoir wettability and the role of wettability in displacement has been the subject of some 50 or so publications. Even so, many aspects of wettability are not well understood and there is no general agreement on a satisfactory method of characterizing it. Opinions as to the optimum wettability condition for recovery cover the spectrum from strongly water-wet through weakly water-wet or intermediately wet to strongly oil-wet. It has recently been suggested that a mixed wettability condition can give high ultimate recoveries. SPEJ P. 221

scholarly journals Wettability Effects on Capillary Pressure, Relative Permeability, and Irredcucible Saturation Using Porous Plate

2014 ◽  
Vol 2014 ◽  
pp. 1-12 ◽  
Author(s):  
Olugbenga Falode ◽  
Edo Manuel
Keyword(s):  
Porous Media ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Water Saturation ◽  
Porous Plate ◽  
Reservoir Rock ◽  
Flow In Porous Media ◽  
Wettability Alteration ◽  
Initial Water ◽  
Phase Saturation

An understanding of the mechanisms by which oil is displaced from porous media requires the knowledge of the role of wettability and capillary forces in the displacement process. The determination of representative capillary pressure (Pc) data and wettability index of a reservoir rock is needed for the prediction of the fluids distribution in the reservoir: the initial water saturation and the volume of reserves. This study shows how wettability alteration of an initially water-wet reservoir rock to oil-wet affects the properties that govern multiphase flow in porous media, that is, capillary pressure, relative permeability, and irreducible saturation. Initial water-wet reservoir core samples with porosities ranging from 23 to 33%, absolute air permeability of 50 to 233 md, and initial brine saturation of 63 to 87% were first tested as water-wet samples under air-brine system. This yielded irreducible wetting phase saturation of 19 to 21%. The samples were later tested after modifying their wettability to oil-wet using a surfactant obtained from glycerophtalic paint; and the results yielded irreducible wetting phase saturation of 25 to 34%. From the results of these experiments, changing the wettability of the samples to oil-wet improved the recovery of the wetting phase.

Capillary Pressure Effects on Estimating the Enhanced-Oil-Recovery Potential During Low-Salinity and Smart Waterflooding

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 481-496 ◽  
Author(s):  
Pål Østebø Andersen
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Low Salinity ◽  
Smart Water ◽  
Relative Permeability Curves

Summary Many experimental studies have investigated smart water and low-salinity waterflooding and observed significant incremental oil recovery after changes in the injected-brine composition. The common approach to model such enhanced-oil-recovery (EOR) mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness can retain much oil at the outlet of the flooded core because of the capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in highly permeable cores at typical laboratory rates. Injecting a brine that changes the wetting state to less-oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation. This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing coreflooding that accounts for wettability changes caused by changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability-alteration (WA) component coupled to the shifting of relative permeability curves and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically because of the changing of one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and the magnitude of capillary end effects can be reduced because of increased water-wetness or because of a reduction in water relative permeability giving a greater viscous drag on the oil.

Analytical Solutions and Derivation of Relative Permeabilities for Water-Heavy Oil Displacement and Gas-Heavy Oil Gravity Drainage Under Non-Isothermal Conditions

2016 ◽  
Vol 19 (01) ◽  
pp. 181-191 ◽  
Author(s):  
F. J. Argüelles-Vivas ◽  
T.. Babadagli
Keyword(s):  
Temperature Gradient ◽  
Relative Permeability ◽  
Heavy Oil ◽  
Variable Temperature ◽  
Spontaneous Imbibition ◽  
Analytical Models ◽  
Gravity Drainage ◽  
Positive Temperature ◽  
Relative Permeability Curves ◽  
Isothermal Gas

Summary Analytical models were developed for non-isothermal gas/heavy-oil gravity drainage and water-heavy oil displacements in round capillary tubes including the effects of a temperature gradient throughout the system. By use of the model solution for a bundle of capillaries, relative permeability curves were generated at different temperature conditions. The results showed that water/gas-heavy oil interface location, oil-drainage velocity, and production rate depend on the change of oil properties with temperature. The displacement of heavy oil by water or gas was accelerated under a positive temperature gradient, including the spontaneous imbibition of water. Relative permeability curves were greatly affected by temperature gradient and showed significant changes compared with the curves at constant temperature. Clarifications were made as to the effect of variable temperature compared with the constant (but high) temperatures throughout the bundle of capillaries.

A Machine Learning Methodology for Rock-Typing Using Relative Permeability Curves

2021 ◽  
Author(s):  
Carlos Esteban Alfonso ◽  
Frédérique Fournier ◽  
Victor Alcobia
Keyword(s):  
Machine Learning ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Fractional Flow ◽  
Flow Curves ◽  
Rock Types ◽  
Rock Typing ◽  
Relative Permeability Curves ◽  
Permeability Data

Abstract The determination of the petrophysical rock-types often lacks the inclusion of measured multiphase flow properties as the relative permeability curves. This is either the consequence of a limited number of SCAL relative permeability experiments, or due to the difficulty of linking the relative permeability characteristics to standard rock-types stemming from porosity, permeability and capillary pressure. However, as soon as the number of relative permeability curves is significant, they can be processed under the machine learning methodology stated by this paper. The process leads to an automatic definition of relative permeability based rock-types, from a precise and objective characterization of the curve shapes, which would not be achieved with a manual process. It improves the characterization of petrophysical rock-types, prior to their use in static and dynamic modeling. The machine learning approach analyzes the shapes of curves for their automatic classification. It develops a pattern recognition process combining the use of principal component analysis with a non-supervised clustering scheme. Before this, the set of relative permeability curves are pre-processed (normalization with the integration of irreducible water and residual oil saturations for the SCAL relative permeability samples from an imbibition experiment) and integrated under fractional flow curves. Fractional flow curves proved to be an effective way to unify the relative permeability of the two fluid phases, in a unique curve that characterizes the specific poral efficiency displacement of this rock sample. The methodology has been tested in a real data set from a carbonate reservoir having a significant number of relative permeability curves available for the study, in addition to capillary pressure, porosity and permeability data. The results evidenced the successful grouping of the relative permeability samples, according to their fractional flow curves, which allowed the classification of the rocks from poor to best displacement efficiency. This demonstrates the feasibility of the machine learning process for defining automatically rock-types from relative permeability data. The fractional flow rock-types were compared to rock-types obtained from capillary pressure analysis. The results indicated a lack of correspondence between the two series of rock-types, which testifies the additional information brought by the relative permeability data in a rock-typing study. Our results also expose the importance of having good quality SCAL experiments, with an accurate characterization of the saturation end-points, which are used for the normalization of the curves, and a consistent sampling for both capillary pressure and relative permeability measurements.

scholarly journals In-House Developed Kr Estimator: Implemented to Analyze the Sensitivity of Relative Permeability Data to Variations in Wetting Phase Saturation

2011 ◽  
Vol 29 (6) ◽  
pp. 817-825 ◽  
Author(s):  
Muhammad Khurram Zahoor
Keyword(s):  
Porous Medium ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Relative Permeability ◽  
State Of The Art ◽  
Data Generation ◽  
Phase Saturation ◽  
Complex Models ◽  
Relative Permeability Curves ◽  
Very High

Reservoir surveillance always requires fast, unproblematic access and solution to different relative permeability models which have been developed from time to time. In addition, complex models sometimes require in-depth knowledge of mathematics for solution prior to use them for data generation. For this purpose, in-house software has been designed to generate rigorous relative permeability curves, with a provision to include users own relative permeability models, a part from built-in various relative permeability correlations. The developed software with state-of-the-art algorithms has been used to analyze the effect of variations in residual and maximum wetting phase saturation on relative permeability curves for a porous medium having very high non-uniformity in pore size distribution. To further increase the spectrum of the study, two relative permeability models, i.e., Pirson's correlation and Brooks and Corey model has been used and the obtained results show that the later model is more sensitive to such variations.

scholarly journals Uncertainty span for relative permeability and capillary pressure by varying wettability and spatial flow directions utilizing pore scale modelling

2020 ◽  
Vol 146 ◽  
pp. 01002
Author(s):  
Thomas Ramstad ◽  
Anders Kristoffersen ◽  
Einar Ebeltoft
Keyword(s):  
Continental Shelf ◽  
Pore Structure ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Phase Flow ◽  
Pore Scale ◽  
Full Field ◽  
Scale Modelling ◽  
Relative Permeability Curves ◽  
Norwegian Continental Shelf

Relative permeability and capillary pressure are key properties within special core analysis and provide crucial information for full field simulation models. These properties are traditionally obtained by multi-phase flow experiments, however pore scale modelling has during the last decade shown to add significant information as well as being less time-consuming to obtain. Pore scale modelling has been performed by using the lattice-Boltzmann method directly on the digital rock models obtained by high resolution micro-CT images on end-trims available when plugs are prepared for traditional SCAL-experiments. These digital rock models map the pore-structure and are used for direct simulations of two-phase flow to relative permeability curves. Various types of wettability conditions are introduced by a wettability map that opens for local variations of wettability on the pore space at the pore level. Focus have been to distribute realistic wettabilities representative for the Norwegian Continental Shelf which is experiencing weakly-wetting conditions and no strong preference neither to water nor oil. Spanning a realistic wettability-map and enabling flow in three directions, a large amount of relative permeability curves is obtained. The resulting relative permeabilities hence estimate the uncertainty of the obtained flow properties on a spatial but specific pore structure with varying, but realistic wettabilities. The obtained relative permeability curves are compared with results obtained by traditional SCAL-analysis on similar core material from the Norwegian Continental Shelf. The results are also compared with the SCAL-model provided for full field simulations for the same field. The results from the pore scale simulations are within the uncertainty span of the SCAL models, mimic the traditional SCAL-experiments and shows that pore scale modelling can provide a time- and cost-effective tool to provide SCAL-models with uncertainties.

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