A Liquid-Freon Permeameter

1962 ◽  
Vol 2 (01) ◽  
pp. 18-20
Author(s):  
B.G. Hurd
Keyword(s):  
Gas Permeability ◽  
Reservoir Rock ◽  
Explosion Hazard ◽  
Petroleum Reservoir ◽  
Laboratory Equipment ◽  
Reservoir Rocks ◽  
Rock Samples ◽  
Halogenated Hydrocarbon ◽  
Liquid Saturation ◽  
Gas Pressures

HURD, B.G., SOCONY MOBIL OIL CO., INC., DALLAS, TEX. Abstract A liquid-Freon permeameter suitable for making routine permeability determinations on small plug samples is described. The instrument is characterized by simplicity of design and ease of operation, and can be assembled inexpensively from stock items of laboratory equipment. It combines the unique advantages of both liquid and gas permeameters while eliminating many undesirable features of both general classes of instruments. Precision and accuracy of the specific Freon permeability measurements compare favorably with results of conventional liquid and gas permeameters. Introduction The liquid-Freon permeameter described in this paper was designed and built for special investigations of the properties of petroleum reservoir rocks. However, its unique advantages over conventional gas and liquid permeameters make it eminently suitable for routine use in the core analysis of small plug samples. In general, gas permeameters are very popular because of their simplicity of design and ease of operation. However, apparent gas permeabilities are normally higher than true specific permeabilities unless special corrections for gas-slippage are applied. Since these corrections require two or more measurements at different internal gas pressures, much of the time advantage of the specific gas permeability measurements is lost. Liquid permeability measurements, on the other hand, require no slip correction, but liquid saturation of the sample is time-consuming and difficult to insure. Often, too, the saturating liquid must be extracted or dried from the plug before it can be used for another experiment. The liquid Freon permeameter described herein retains the inherent accuracy of the liquid permeameter, while affording the speed and ease of operation of the gas permeameter. Freon-12 (dichlorodifluoromethane) is a halogenated hydrocarbon, immiscible in the liquid phase with water. It may be considered as an oil phase in laboratory fluid-flow studies. Like butane and propane, it is a gas at normal room temperatures and atmospheric pressure but can be liquefied at moderate pressures. Complete liquid saturation of a plug sample with any of these fluids can be easily achieved by condensing vapors in the sample and operating the permeameter at a pressure above the vapor pressure of the liquid. Freon-12 is superior to butane or propane for permeability measurements only in that it is relatively non toxic and completely incombustible, and thus presents no fire or explosion hazard. Freon-12 is believed to be completely nonreactive with most petroleum-reservoir rock samples. It volatilizes immediately from a plug on depressurizing to leave a clean, dry sample suitable for subsequent experiments. Thus, the inherent risk of changing physical properties of rock samples by cleaning and drying operations between permeability measurement and subsequent experiments is eliminated. DESCRIPTION OF THE PERMEAMETER The design of the liquid Freon permeameter is shown schematically in Fig. 1. SPEJ P. 18^

scholarly journals Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2233 ◽  
Author(s):  
Aliya Mukhametdinova ◽  
Andrey Kazak ◽  
Tagir Karamov ◽  
Natalia Bogdanovich ◽  
Maksim Serkin ◽  
...  
Keyword(s):  
Gas Permeability ◽  
Total Porosity ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Crushed Rock ◽  
Void Space ◽  
Reservoir Properties ◽  
Rock Samples ◽  
Liquid Saturation ◽  
Imaging Results

This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP porosity matched both NMR and imaging results and highlighted the different effects of solvent extraction on throat size distribution. PDP core-plug gas permeability measurements were consistent but overestimated in comparison to PSS results, with the difference reaching two orders of magnitude. SEM proved to be the only feasible method for void-scale imaging with a spatial resolution up to 5 nm. The results confirmed the presence of natural voids of two major types. The first type was organic matter (OM)-hosted pores, with dimensions of less than 500 nm. The second type was sporadic voids in the mineral matrix (biogenic clasts), rarely larger than 250 nm. Comparisons between whole-core and core-plug reservoir properties showed substantial differences in both porosity (by a factor of 2) and permeability (up to 4 orders of magnitude) caused by spatial heterogeneity and scaling.

A new technique utilizing Scanning Electron Microscopy at low temperature and voltage to analyze native-state reservoir rocks

1989 ◽  
Vol 47 ◽  
pp. 686-687
Author(s):  
C. J. Stuart ◽  
L.-C. Liang ◽  
J. B. Toney
Keyword(s):  
Solid State ◽  
Low Voltage ◽  
Thermal Contact ◽  
High Vacuum ◽  
Reservoir Rock ◽  
Petroleum Reservoir ◽  
Native State ◽  
Analytical Technique ◽  
Reservoir Rocks ◽  
Scanning Electron

A new analytical technique has been developed to allow direct imaging of native-state petroleum reservoir rocks by the use of the scanning electron microscope (SEM) in a low voltage mode combined with a solid-state cryo-system device. The SEM investigation of native-state reservoir rock samples is important since it enables direct visualization of: (1) the spatial distributions of the fluids in the pore system; (2) clay minerals in their natural hydrated states; (3) the native mineralogy; (4) combined effects on the reservoir's wettability and permeability. The technique uses low voltage SEM to image the uncoated surface of the wet sample at a high vacuum and applies the cryostage to control the vapor pressure of the fluid phase while imaging. A differentially pumped environmental chamber is not required with this approach.This technique utilizes a solid-state thermoelectric cooler device (TED) to achieve the required sample cooling. The TED operates on the Peltier principle permitting the surface of the TED to reach a temperature as low as 110 degrees centigrade below its reference temperature. A sample stage is refitted with a TED substage which is water-cooled. The water-cooling of the substage coupled with the TED allows a precise control of the sample temperature. The sample is fixed to the substage so that it is in direct thermal contact with the TED. The TED is then biased (by the use of DC currents) to provide the effective cooling necessary to minimize vaporization of the interstitial fluids in the sample. The sample and stage temperatures are constantly monitored by means of two microtype-K thermocouple devices. With this approach, no liquid nitrogen is needed for this technique.

scholarly journals Liquid and Gas Corrected Permeability Correlation for Heterogeneous Carbonate Reservoir Rocks

2020 ◽  
pp. 36-50
Author(s):  
Sadonya Jamal Mustafa ◽  
Fraidoon Rashid ◽  
Khalid Mahmmud Ismail
Keyword(s):  
Gas Permeability ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Reservoir Properties ◽  
Reservoir Rocks ◽  
Rock Types ◽  
Liquid Permeability ◽  
Porosity And Permeability ◽  
Permeability Distribution ◽  
Reservoir Type

Permeability is considered as an efficient parameter for reservoir modelling and simulation in different types of rocks. The performance of a dynamic model for estimation of reservoir properties based on liquid permeability has been widely established for reservoir rocks. Consequently, the validated module can be applied into another reservoir type with examination of the validity and applicability of the outcomes. In this study the heterogeneous carbonate reservoir rock samples of the Tertiary Baba Formation have been collected to create a new module for estimation of the brine permeability from the corrected gas permeability. In addition, three previously published equations of different reservoir rock types were evaluated using the heterogenous carbonate samples. The porosity and permeability relationships, permeability distribution, pore system and rock microstructures are the dominant factors that influenced on the limitation of these modules for calculating absolute liquid permeability from the klinkenberg-corrected permeability. The most accurate equation throughout the selected samples in this study was the heterogenous module and the lowest quality permeability estimation was derived from the sandstone module.

scholarly journals Digital Rock Samples Porosity Analysis by OTSU Thresholding Technique Using MATLAB

2020 ◽  
Vol 21 (3) ◽  
pp. 57-66
Author(s):  
Yahya Jirjees Tawfeeq ◽  
Jalal A. Al-Sudani
Keyword(s):  
Image Processing ◽  
Pore Structure ◽  
Thin Section ◽  
Digital Image ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Reservoir Rock ◽  
Reservoir Rocks ◽  
Rock Samples ◽  
Digital Rock

Porosity plays an essential role in petroleum engineering. It controls fluid storage in aquifers, connectivity of the pore structure control fluid flow through reservoir formations. To quantify the relationships between porosity, storage, transport and rock properties, however, the pore structure must be measured and quantitatively described. Porosity estimation of digital image utilizing image processing essential for the reservoir rock analysis since the sample 2D porosity briefly described. The regular procedure utilizes the binarization process, which uses the pixel value threshold to convert the color and grayscale images to binary images. The idea is to accommodate the blue regions entirely with pores and transform it to white in resulting binary image. This paper presents the possibilities of using image processing for determining digital 2D rock samples porosity in carbonate reservoir rocks. MATLAB code created which automatically segment and determine the digital rock porosity, based on the OTSU's thresholding algorithm. In this work, twenty-two samples of 2D thin section petrographic image reservoir rocks of one Iraqi oil field are studied. The examples of thin section images are processed and digitized, utilizing MATLAB programming. In the present study, we have focused on determining of micro and macroporosity of the digital image. Also, some pore void characteristics, such as area and perimeter, were calculated. Digital 2D image analysis results are compared to laboratory core investigation results to determine the strength and restrictions of the digital image interpretation techniques. Thin microscopic image porosity determined using OTSU technique showed a moderate match with core porosity.

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.

scholarly journals Analysis of filtration and electrical properties anisotropy of terrigenous reservoir rocks (for DDB axial zone reservoirs)

2019 ◽  
Keyword(s):  
Electrical Resistivity ◽  
Gas Permeability ◽  
Vertical Direction ◽  
Absolute Permeability ◽  
Electrical Anisotropy ◽  
Reservoir Rocks ◽  
Vertical Permeability ◽  
Irreducible Water Saturation ◽  
Horizontal Permeability ◽  
Filtration Properties

The paper focuses on the filtration and electrical anisotropy coefficients and relationship between vertical and horizontal permeability in sandstone reservoir rocks. Field case study of DDB reservoir rocks. Petrophysical properties and parameters are estimated from core and log data from a Moscovian and Serpukhovian stages of Dnipro-Donetsk Basin (West-Shebelynka area well 701-Bis and South-Kolomak area well 31). Routine core analysis included estimation of absolute permeability, open porosity, irreducible water saturation and electrical resistivity (on dry and saturated by mineralized solution) of 40 core samples along two orthogonal directions. Shale fraction is estimated using well logging data in wells which are analyzed. The authors report that reservoir rocks are represented by compacted poor-porous (φ <10 %), low permeable (k<1mD) laminated sandstone with different ratios of clay minerals (Vsh from 0,03 to 0,7) and high volume of micaceous minerals (in some cases 20-30 %). Research theory. One of the main objectives of the work is to develop empirical correlation between vertical permeability and other capacitive and filtration properties for compacted sandstone reservoirs. A modified Kozeny-Carman equation and the concept of hydraulic average radius form the basis for the technique. Results. Coefficients of the anisotropy of gas permeability (IA) and electrical resistivity (λ) are defined based on the results of petrophysical studies. The experiments proved that IA lies in a range from 0,49 to 5 and λ from 0,77 to 1,06. Permeability and electrical resistivity anisotropy in most cases have horizontal distribution. It has been shown that in West-Shebelynka area sample №1 (depth 4933 m) there is probably no fluids flow in vertical direction and in samples №№3 and 15 fractures have the vertical orientation. We have also found that the values of electrical and filtration anisotropy for all samples of South-Kolomak area are similar, this characterized the unidirectionality in their filtration properties, as well as the fact that the motion of the fluid flow mainly in the horizontal direction. In the studied rocks the degree of anisotropy has been concluded to depend on the volume of clay and micaceous minerals, their stratification, fractures, density, and their orientation. New correlation between vertical permeability, horizontal permeability and effective porosity are developed for Late Carboniferous DDB intervals that are analyzed.

A faster method for erosion and dilation of reservoir pore-complex images

1988 ◽  
Vol 25 (7) ◽  
pp. 1128-1131 ◽  
Author(s):  
J. R. Parker
Keyword(s):  
Flow Behavior ◽  
Reservoir Rock ◽  
Two Dimensional ◽  
Thin Sections ◽  
Reservoir Rocks ◽  
Image Processing Techniques ◽  
The Third ◽  
Computer Image Processing ◽  
Third Dimension ◽  
Processing Techniques

Studies of thin sections of reservoir rock have been conducted for some time with the goal of understanding flow behavior and estimating physical properties. These sections are essentially two dimensional, but it has always been assumed that the results obtained can be extrapolated to the third dimension. Computer image-processing techniques are often used in this sort of analysis because of the large amounts of data contained in a single digitized section image. One of the methods used to process these images is erosion–dilation, wherein layers of each pore are stripped off (erosion) and then replaced (dilation). This results in a smoothing of the pore perimeters and can be used to estimate pore radii, volume, and roughness. Because of the size of each image, erosion–dilation of images of the pore complex of reservoir rocks is a time-consuming process. A new method called global erosion is much faster, with no increase in memory requirement or decrease in accuracy. This should permit the processing of larger images or a greater number of small images than does the standard method.

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