Interfacial phenomena in petroleum reservoir conditions related to fluid-fluid interactions and rock-fluid interactions: Formulation effects and in porous medium test

2021 ◽  
pp. 109076
Author(s):  
Ingrid Velasquez ◽  
Iris Silva ◽  
Lesbia Martínez ◽  
Luz Rattia ◽  
Henry Labrador ◽  
...  
Keyword(s):  
Porous Medium ◽  
Interfacial Phenomena ◽  
Petroleum Reservoir ◽  
Reservoir Conditions ◽  
Fluid Interactions

How ZrO2 nanoparticles improve the oil recovery by affecting the interfacial phenomena in the reservoir conditions?

2018 ◽  
Vol 252 ◽  
pp. 158-168 ◽  
Author(s):  
Hosein Rezvani ◽  
Ali Khalilnezhad ◽  
Parastoo Ganji ◽  
Yousef Kazemzadeh
Keyword(s):  
Oil Recovery ◽  
Interfacial Phenomena ◽  
Zro2 Nanoparticles ◽  
Reservoir Conditions

Bulk Modulus of Hydrocarbon Fluids After Injection with Supercritical CO2 at Reservoir Conditions

2021 ◽  
Author(s):  
Mohamed Eid Kandil
Keyword(s):  
Mechanical Properties ◽  
Bulk Modulus ◽  
Supercritical Co2 ◽  
Pore Space ◽  
Fluid Phase ◽  
Petroleum Reservoir ◽  
Fluid Mixture ◽  
Mixture Density ◽  
Well Completion ◽  
Reservoir Conditions

Abstract The mechanical properties of hydrocarbon reservoirs significantly depend on the elastic properties of the fluids occupying the pore space in the rock frame. Accurate data and models for the mechanical properties of fluid mixtures in a petroleum reservoir containing supercritical CO2 should be available at the same reservoir conditions for reliable design of well-completion, maximizing reservoir productivity, and minimizing risk in drilling operations. This work investigates the change in the bulk modulus of the higher hydrocarbon fluid (decane C10H22) after the injection with supercritical CO2 at reservoir conditions. The isothermal bulk modulus βT of liquids under pressure, simply defined as the first-order derivative of pressure with respect to volume, is determined in this study from the derivative of pressure with respect to density. The density data were obtained from experimental measurements of mixtures of supercritical CO2 + C10H22 for a range of CO2 mole fractions from 0 to 0.73, at temperatures from 40 to 137 °C and pressures up to 12000 psi. The isothermal derivative coefficients of the pressure as a function of density are reported for each CO2 concentration measured in this work. Common fluid-substitution models, including the Gassmann model, which is only valid for the isothermal regime, have limited predictive power because most fluids are treated as simple fluids, with their mechanical properties only characterized by their densities. However, under different environments, such as when supercritical CO2 is injected into the geological formation, the fluid phase and its mechanical properties can vary dramatically. At high pressure, the density of CO2 can equal to that of the hydrocarbon phase ρ(CO2)/ρ(C10H22) ≈ 1, while the bulk modulus of CO2 remains as low as only βT(CO2)/βT(C10H22) ≈ 7 %. Excessive decrease in the bulk modulus can easily cause subsidence, although the pore pressure and the fluid mixture density remain unchanged, even at pressures up to 4000 psi.

THE IMPORTANCE OF WETTABILITY AND WETTABILITY TESTING METHODS USED IN THE OIL INDUSTRY

1995 ◽  
Vol 35 (1) ◽  
pp. 143 ◽  
Author(s):  
S.R.J. Clinch ◽  
P.J. Boult ◽  
R.A. Hayes
Keyword(s):  
Oil Recovery ◽  
Rock Strength ◽  
Pore Space ◽  
Oil Industry ◽  
Petroleum Reservoir ◽  
Pressure Data ◽  
Reservoir Conditions ◽  
Recent Method ◽  
Production Problems

The wettability of a petroleum reservoir governs the location of fluids within its pore space and hence the movement of fluids through it during production. Properties that may be affected by wettability include resistivity, capillary pressure, relative permeability and rock strength as well as behaviour during waterflood and enhanced oil recovery. Generally every reservoir is initially assumed to be water wet. When production problems arise, the wettability of a reservoir will only be questioned when all other possibilities have been accounted for. By correctly determining the wettability of a reservoir more accurate models can be provided for reservoir simulation, which in turn will improve the prediction of future field performance.Many methods of varying difficulty and accuracy can be used to measure wettability. However, they can only be as good as the quality of the fluid samples used. It is important to understand that reliable results are only obtained when sample contamination is minimised and experimental control is maximised. Some wettability experiments can be carried out at reservoir conditions, which may be more representative, but also more susceptible to contamination.In an oil reservoir either oil or brine can be the most wetting phase and gas is normally the least wetting phase. From a thorough investigation of downhole logs and production data it may be possible to identify wetting anomalies. Examining formation pressure data is the most recent method proposed for determining wettability.

Correlations of Physical Properties of Porous Media

1967 ◽  
Vol 7 (03) ◽  
pp. 266-272 ◽  
Author(s):  
W. Douglas Von Gonten ◽  
R.L. Whiting
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Regression Analysis ◽  
Physical Properties ◽  
Physical Property ◽  
Rock Properties ◽  
Petroleum Reservoir ◽  
Formation Factor ◽  
Naturally Occurring ◽  
Formation Resistivity

Abstract Regression analysis was used to correlate the physical properties of 478 sandstone and 90 carbonate core samples. Porosity, permeability, electrical formation resistivity factor, capillary pressure and the sonic velocity of the shear and compressional waves were measured. Prediction equations for porosity, permeability and electrical formation resistivity factor were found which should be useful in understanding the relationships between the physical properties of porous media in formation evaluation. Introduction The physical properties of porous media are important to the petroleum engineer and geologist. To evaluate fully the potential and behavior of a subsurface formation such as a petroleum reservoir, certain physical properties of the porous medium must be known. The problem of accurately determining physical properties of subsurface formations has not been solved because many determinations must be made by indirect measurements and because of the difficulties caused by complex pore structure and presence of clays in most naturally occurring porous media. Due to the difficulty in measuring some of the physical properties of porous media, it would be advantageous to be able to predict a certain physical property of a rock from other physical properties of the rock which could be measured more easily and more accurately. Since most potential reservoir rocks are heterogeneous, relationships between the physical properties are very complex and thus far no satisfactory correlations based on theory or laboratory models have been developed. It appears that empirical relationships obtained by measuring the physical properties of a large number of samples of naturally occurring porous media and applying regression analysis to develop for one physical property in terms of other rock properties is the best approach. REVIEW LITERATURE The three physical properties used as dependent variables for correlating purposes were porosity, permeability and formation factor. Since formation factor is more difficult to determine, a brief review of the literature is provided on this property. The first work on determining formation factors was published by Archie in 1942. He defined this property of a porous medium as Ro ...............................(1) F =RW where Ro is the resistivity of the porous medium when completely saturated with a brine of resistivity Rw. Archie found the best correlation between formation factor and porosity was the following equation, F = - m..................................... (2) where is the porosity fraction and m is the constant characteristic of the rock. The value of m was 1.3 for unconsolidated sand packs, and ranged from 1.8 to 2.0 for consolidated sandstones. In 1950 Patnode and Wyllie and De Witte observed that the formation factor as determined by Eq. 1 was valid only when the porous medium contained no conductive solids such as clay or shale. When conductive solids are -present the formation factor is also dependent on the resistivity of the saturating fluid. Therefore, in samples containing conductive solids the formation factor decreased as resistivity of the saturating fluid increased. Because of this, the measured formation factor was called the apparent formation factor and was designated Fa. Patnode and Wyllie proposed the following equation. SPEJ P. 266ˆ

Tandem scanning confocal light microscopy as compared with x-ray diffraction for characterizing the behavior of clays in fluid-saturated petroleum reservoir rock

1989 ◽  
Vol 47 ◽  
pp. 148-149
Author(s):  
C.J. Stuart ◽  
B.E. Viani ◽  
J. Walker ◽  
T.H. Levesque
Keyword(s):  
Light Microscopy ◽  
Image Plane ◽  
Reservoir Rock ◽  
Depth Of Field ◽  
Objective Lens ◽  
Scanning System ◽  
Light Sources ◽  
Petroleum Reservoir ◽  
Image Recording ◽  
Scan Speed

Many techniques of imaging used to characterize petroleum reservoir rocks are applied to dehydrated specimens. In order to directly study behavior of fines in reservoir rock at conditions similar to those found in-situ these materials need to be characterized in a fluid saturated state.Standard light microscopy can be used on wet specimens but depth of field and focus cannot be obtained; by using the Tandem Scanning Confocal Microscope (TSM) images can be produced from thin focused layers with high contrast and resolution. Optical sectioning and extended focus images are then produced with the microscope. The TSM uses reflected light, bulk specimens, and wet samples as opposed to thin section analysis used in standard light microscopy. The TSM also has additional advantages: the high scan speed, the ability to use a variety of light sources to produce real color images, and the simple, small size scanning system. The TSM has frame rates in excess of normal TV rates with many more lines of resolution. This is accomplished by incorporating a method of parallel image scanning and detection. The parallel scanning in the TSM is accomplished by means of multiple apertures in a disk which is positioned in the intermediate image plane of the objective lens. Thousands of apertures are distributed in an annulus, so that as the disk is spun, the specimen is illuminated simultaneously by a large number of scanning beams with uniform illumination. The high frame speeds greatly simplify the task of image recording since any of the normally used devices such as photographic cameras, normal or low light TV cameras, VCR or optical disks can be used without modification. Any frame store device compatible with a standard TV camera may be used to digitize TSM images.

Sign in / Sign up

Export Citation Format

Share Document