scholarly journals Irreducible Water Saturation from Capillary Pressure and Electrical Resistivity Measurements

2008 ◽  
Vol 63 (2) ◽  
pp. 203-217 ◽  
Author(s):  
A. M. Attia ◽  
D. Fratta ◽  
Z. Bassiouni
Keyword(s):  
Electrical Resistivity ◽  
Capillary Pressure ◽  
Water Saturation ◽  
Resistivity Measurements ◽  
Irreducible Water Saturation

scholarly journals Effects of Foam Microbubbles on Electrical Resistivity and Capillary Pressure of Partially Saturated Porous Media

Molecules ◽  
2020 ◽  
Vol 25 (15) ◽  
pp. 3385 ◽  
Author(s):  
Abdulrauf R. Adebayo ◽  
Abubakar Isah ◽  
Mohamed Mahmoud ◽  
Dhafer Al-Shehri
Keyword(s):  
Porous Media ◽  
Electrical Resistivity ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Water Saturation ◽  
Porous Plate ◽  
Fluid Distribution ◽  
Cross Sectional ◽  
Injection Process ◽  
Saturation Exponent

Laboratory measurements of capillary pressure (Pc) and the electrical resistivity index (RI) of reservoir rocks are used to calibrate well logging tools and to determine reservoir fluid distribution. Significant studies on the methods and factors affecting these measurements in rocks containing oil, gas, and water are adequately reported in the literature. However, with the advent of chemical enhanced oil recovery (EOR) methods, surfactants are mixed with injection fluids to generate foam to enhance the gas injection process. Foam is a complex and non-Newtonian fluid whose behavior in porous media is different from conventional reservoir fluids. As a result, the effect of foam on Pc and the reliability of using known rock models such as the Archie equation to fit experimental resistivity data in rocks containing foam are yet to be ascertained. In this study, we investigated the effect of foam on the behavior of both Pc and RI curves in sandstone and carbonate rocks using both porous plate and two-pole resistivity methods at ambient temperature. Our results consistently showed that for a given water saturation (Sw), the RI of a rock increases in the presence of foam than without foam. We found that, below a critical Sw, the resistivity of a rock containing foam continues to rise rapidly. We argue, based on knowledge of foam behavior in porous media, that this critical Sw represents the regime where the foam texture begins to become finer, and it is dependent on the properties of the rock and the foam. Nonetheless, the Archie model fits the experimental data of the rocks but with resulting saturation exponents that are higher than conventional gas–water rock systems. The degree of variation in the saturation exponents between the two fluid systems also depends on the rock and fluid properties. A theory is presented to explain this phenomenon. We also found that foam affects the saturation exponent in a similar way as oil-wet rocks in the sense that they decrease the cross-sectional area of water available in the pores for current flow. Foam appears to have competing and opposite effects caused by the presence of clay, micropores, and conducting minerals, which tend to lower the saturation exponent at low Sw. Finally, the Pc curve is consistently lower in foam than without foam for the same Sw.

Quantitative comparison of processes of oil- and water-based mud-filtrate invasion and corresponding effects on borehole resistivity measurements

Geophysics ◽  
2009 ◽  
Vol 74 (1) ◽  
pp. E57-E73 ◽  
Author(s):  
Jesús M. Salazar ◽  
Carlos Torres-Verdín
Keyword(s):  
Electrical Resistivity ◽  
Flow Rate ◽  
Water Saturation ◽  
Base Case ◽  
Petrophysical Properties ◽  
Resistivity Measurements ◽  
Fluid Saturation ◽  
Mud Cake ◽  
Water Based ◽  
Mud Filtrate

Some laboratory and qualitative studies have documented the influence of water-based mud(WBM)-filtrate invasion on borehole resistivity measurements. Negligible work, however, has been devoted to studying the effects of oil-based mud(OBM)-filtrate invasion on well logs and the corresponding impact on the estimation of petrophysical properties. We quantitatively compare the effects of WBM- and OBM-filtrate invasion on borehole resistivity measurements. We simulate the process of mud-filtrate invasion into a porous and permeable rock formation assuming 1D radial distributions of fluid saturation and fluid properties while other petrophysical properties remain constant. To simulate the process of mud-filtrate invasion, we calculate a time-dependent flow rate of OBM-filtrate invasion by adapting the available formulation of the physics of WBM-filtrate invasion. This approach includes the dynamically coupled effects of mud-cake growth and multiphase filtrate invasion. Simulations are performed with a commercial adaptive-implicit compositional formulation that enables the quantification of effects caused by additional components of mud-filtrate and native fluids. The formation under analysis is 100% water saturated (base case) andis invaded with a single-component OBM. Subsequently, we perform simulations of WBM filtrate invading the same formation assuming that it is hydrocarbon bearing, and compare the results to those obtained in the presence of OBM. At the end of this process, we invoke Archie’s equation to calculate the radial distribution of electrical resistivity from the simulated radial distributions of water saturation and salt concentration and compare the effects of invasion on borehole resistivity measurements acquired in the presence of OBM and WBM. Simulations confirm that the flow rate of OBM-filtrate invasion remains controlled by the initial mud-cake permeability and formation petrophysical properties, specifically capillary pressure and relative permeability. Moreover, WBM causes radial lengths of invasion 15%–40% larger than those associated with OBM as observed on the radial distributions of electrical resistivity. It is found also that, in general, flow rates of WBM-filtrate invasion are higher than those of OBM-filtrate invasion caused by viscosity contrasts between OBM filtrate and native fluids, which slow down the process of invasion. Such a conclusion is validated by the marginal variability of array-induction resistivity measurements observed in simulations of OBM invasion compared with those of WBM invasion.

APPLICATION OF RESISTIVITY INVERSION MODELLING TO ENHANCE WATER SATURATION CALCULATIONS FROM WIRELINE LOGS

2000 ◽  
Vol 40 (1) ◽  
pp. 355
Author(s):  
C.J. Shield
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Strong Relationship ◽  
Data Set ◽  
Hydrocarbon Reservoir ◽  
The Core ◽  
Irreducible Water Saturation ◽  
Resistivity Logs ◽  
Resistivity Inversion ◽  
Induction Logs

Water saturation (Sw) values calculated from resistivity or induction logs are often higher than those measured from core-derived capillary pressure (Pc) measurements. The core-derived Sw measurements are commonly applied for reservoir simulation in preference to the log-derived Sw calculations. As it is economically and logistically impractical to core every hydrocarbon reservoir, a method of correlating the core-derived Sw to resistivity/induction logs is required. Two-dimensional resistivity modelling is applied to dual laterolog data to ascertain the applicability of this technique.The Griffin and Scindian/Chinook Fields, offshore Western Australia, have been producing hydrocarbons since 1994 from two early-to-middle Cretaceous reservoirs, the clean quartzose sandstones of the Zeepaard Formation and the overlying glauconitic, quartzose sandstones of the Birdrong Formation. Routine and special core analysis of cores recovered from wells intersecting these two reservoirs creates an excellent data set with which to correlate the good quality wireline log data.A strong relationship is noted between the modelled water saturation from resistivity logs, and the irreducible water saturation measured from core capillary pressure data. Correlation between the core-derived permeability and the invasion diameter calculated from the modelled laterolog data is shown to produce a locally applicable means of estimating permeability from the resistivity modelling results.The evaluation of these data from the Griffin and Scindian/Chinook Fields provides a method for reducing appraisal and development well analysis costs, through the closer integration of core and wireline log data at an earlier stage of the field appraisal phase.

A Comprehensive Approach for Assessing the Impacts of Wettability on Oil Production in Carbonate Reservoirs

2012 ◽  
Author(s):  
Marcos Faerstein ◽  
Paulo Couto ◽  
José Alves
Keyword(s):  
Capillary Pressure ◽  
Case Studies ◽  
Water Saturation ◽  
Oil Production ◽  
Comprehensive Approach ◽  
Carbonate Reservoirs ◽  
Irreducible Water Saturation ◽  
Reservoir Simulator ◽  
Correct Understanding ◽  
The Impact

This paper discusses the impacts that rock wettability may have upon the production and recovery of oil with waterflooding in carbonate reservoirs and how it should be modeled. A broad review of the state of the art has been conducted surveying existing disagreements and knowledge gaps, basic definitions, as well as the correct understanding of the physical phenomena and identification of the characteristics of the various wettability scenarios. Case studies conducted with a black oil reservoir simulator evaluated the impact of different wettability scenarios on oil production and recovery. A comprehensive approach considering all the parameters involved in the wettability modeling was applied to the case studies, showing how the behavior of the reservoir varies as a function of their wettability. This paper shows how relative permeability and capillary pressure should be varied to correctly represent different wettability scenarios and consequently assess its impacts on oil production and recovery. The case studies show that the evaluation of the volume of oil in the reservoir is impacted by wettability through the irreducible water saturation and primary drainage capillary pressure and must be considered in the analyses. In long term analyses, mixed-wet scenarios have a higher oil production and recovery. In medium and short term, the water-wet scenarios have the higher recovery, but in relation to oil production, these scenarios are negatively influenced by the smaller volume of oil in place. The main contribution of this paper is the simultaneous analyses of all the parameters involved in the modeling of wettability showing how they impact the behavior of a reservoir. It shows how the parameters must be varied in a heterogeneous reservoir and how heterogeneity impacts the relevance of wettability in the studies.

Estimation of dynamic petrophysical properties of water-bearing sands invaded with oil-base mud from the interpretation of multiple borehole geophysical measurements

Geophysics ◽  
2012 ◽  
Vol 77 (6) ◽  
pp. D209-D227 ◽  
Author(s):  
Zoya Heidari ◽  
Carlos Torres-Verdín
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Radial Distribution ◽  
Apparent Resistivity ◽  
Water Saturation ◽  
Estimation Method ◽  
Petrophysical Properties ◽  
Fluid Saturation ◽  
Irreducible Water Saturation ◽  
Geophysical Measurements

Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.

Electrical resistivity and chemical properties of kerogen isolated from organic-rich mudrocks

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. D643-D655 ◽  
Author(s):  
Anqi Yang ◽  
Gama Firdaus ◽  
Zoya Heidari
Keyword(s):  
Electrical Resistivity ◽  
Water Saturation ◽  
Resonance Spectroscopy ◽  
Chemical Transformations ◽  
Thermal Maturity ◽  
Microscopy Imaging ◽  
Eagle Ford ◽  
Resistivity Measurements ◽  
Low Resistivity ◽  
Geochemical Properties

Low electrical resistivity measurements in organic-rich mudrocks are commonplace in highly mature zones. These low resistivity values are usually difficult to justify and lead to overestimation of water saturation when using conventional resistivity-porosity-saturation models (e.g., dual water and Waxman-Smits). Previous publications suggest that the electrical conductivity of kerogen increases when it thermally matures. This increase in thermal maturity of kerogen might contribute to low resistivity measurements in organic-rich mudrocks. However, electrical properties of kerogen within these rocks have not yet been quantified experimentally. We have introduced a technique to quantify electrical resistivity of kerogen through combined experimental and numerical approaches and quantified electrical resistivity of kerogen samples from the Haynesville and Eagle Ford Formations. We first isolated kerogen from mudrock samples using physical and chemical treatments. The isolated kerogen powder was then compressed into a homogeneous disk. Then, we synthetically matured mudrock and kerogen samples to controlled maturity levels and measured the electrical resistivity and geochemical properties of each sample. The true electrical resistivity of kerogen was then estimated by minimizing the difference between the numerically simulated and measured electrical resistivity of the molded kerogen samples. We have observed a significant decrease in the electrical resistivity of kerogen isolated from the Haynesville (i.e., up to four orders of magnitude) and Eagle Ford (i.e., up to nine orders of magnitude) Formations upon heat treatment from 300°C to 800°C. The decrease in resistivity can be reasoned by the chemical transformations of organic matter through thermal maturation. The results of solid-state [Formula: see text] nuclear magnetic resonance spectroscopy and transmission electron microscopy imaging confirmed increase in graphitization and aromaticity in the kerogen samples as thermal maturity increases. Our outcomes can potentially improve interpretation of electrical resistivity logs in organic-rich mudrocks, such as enhancing well-log-based assessment of in situ hydrocarbon saturation.

Effect of Temperature Level upon Capillary Pressure Curves

1971 ◽  
Vol 11 (01) ◽  
pp. 13-22 ◽  
Author(s):  
Ali A. Sinnokrot ◽  
H.J. Ramey ◽  
S.S. Marsden
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Temperature Increase ◽  
Water Saturation ◽  
Effect Of Temperature ◽  
Temperature Level ◽  
Dynamic Displacement ◽  
Irreducible Water Saturation ◽  
Limestone Sample ◽  
Capillary Pressure Curves

Abstract A number of recent studies of drainage relative permeability ratio by dynamic displacement have permeability ratio by dynamic displacement have indicated temperature sensitivity. Poston et al. found that the irreducible water saturation appeared to increase significantly with temperature-level increase and speculated that capillary pressure saturation data would also change to show this effect. Although there have been capillary pressure-saturation studies which show important pressure-saturation studies which show important differences between laboratory and reservoir conditions (presumably higher temperatures), the effects have usually been attributed to adsorption and desorption of polar components from the liquid phases. There appears to be no systematic studies phases. There appears to be no systematic studies of the effect of temperature level upon capillary pressure. pressure. Equipment was constructed to permit measuring capillary pressures for simple systems at temperatures ranging from room temperature to about 350 deg. F. Drainage and imbibition capillary pressure curves were measured for three consolidated pressure curves were measured for three consolidated sandstones and one limestone sample, at either three or four temperature levels form 70 deg to 325 deg F. Fluid used were a filtered white oil and distilled water. Results for the sandstone samples were similar. The practical irreducible water saturation increased significantly as temperature was raised from 70 deg F to the maximum temperature studies - about 325 deg F. Surprisingly, the hysteresis between drainage and imbibition cycles decreased as temperature increased and was nearly absent at 300 deg F. Results indicated that the sandstone samples became markedly more water-wet as temperature level increased. Results for the limestone sample were quite different. All capillary pressure-saturation curves for the various isotherms were found to lie within the envelope of the room-temperature drainage and imbibition curves. The main objective of this study was to determine whether the supposition of Poston et al. was correct. Results are in agreement with the previous dynamic displacement work. Introduction In 1967, Poston et al reported displacement experiments on unconsolidated sands at elevated temperatures and found that the irreducible water saturation increased with temperature increase. The oil viscosity appeared to have had no real effect on their results. Although less conclusive, practical residual oil saturations (to a producing practical residual oil saturations (to a producing water-oil ratio of 100) appeared to decrease with temperature increase. The results also indicated important increases in both oil and water relative permeabilities as temperature increased. This led permeabilities as temperature increased. This led Poston et al. to suggest that temperature affects. Poston et al. to suggest that temperature affects. the sand wettability. Sessile-drop contact angle measurements indicated that the water-oil-glass contact angle decreased with temperature increase. The results of Poston et al. regarding an increase in irreducible water saturation with temperature increase and the nondependence of this finding on the viscosity ratio deserve more attention. it is a well established concept in the literature that increasing water wetness of sands is reflected in an increase in the irreducible water saturation and an increase in oil recovery efficiency. The effect on a capillary pressure-saturation curve would be to cause a shift toward increasing irreducible wetting-phase saturation. if this is the case, then the studies of McNiel and Moss and Willman et al. should give partial credit for the added oil recovery efficiency involved in hot water flooding to the effect of temperature level upon wettability. In view of the potential importance of hot fluid injection for improving oil recovery and the lack of an adequate description of the flow process and thermodynamics involved, it was decided to study the speculation of Poston et al. that capillary pressure-saturation curves should be temperature pressure-saturation curves should be temperature dependent. This study concerns the effect of temperature level upon capillary pressure-saturation relationships for consolidated porous media. SPEJ p. 13

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