The aim of this work was to obtain the physicochemical properties by SEM, XRD, FTIR analyses and the surface characteristics from carbonate outcrops cores such as pore diameter, surface area, porosity and permeability. The methods used to characterize them were Scanning Electron Microscopy, SEM; X Ray Diffraction, DRX; Fourier Transform Infrared Spectroscopy, FTIR. The porosity and permeability of natural vuggy fractured porous medium from core samples was determined obtained in the laboratory with conventional procedures. The cores have smooth and rough surfaces with porous with several sizes. Some crystals appear in preferential zones mainly composed by calcium, carbon and oxygen. Apparently into free spaces were found the organic materials, organic residues of crude oil. The cores have smooth and rough surfaces with porous with several sizes. Some crystals appear in preferential zones composed by calcium, carbon and oxygen. Apparently into free spaces were found the organic materials, organic residues of crude oil. The main inorganic compound in cores is calcite, (CaCO 3). The porosity was for porous core 26% and for solid core 8.5%. The values obtained show that the cores have permeability where the fluid migrates through the particles at 2.23 × 10 -4 cm/s.
In geologic materials of low hydraulic conductivity (K) such as fine-grained sedimentary rocks and crystalline rocks, diffusion is the principal mechanism of solute transport. Low permeability geologic materials are of interest for waste management programs, carbon sequestration and unconventional petroleum development. Diffusive solute transport occurs in response to concentration gradients and the solute diffuses through interconnected pores and/or fractures. Diffusion of aqueous solute in a porous medium is constrained within the water- saturated portion of the pore spaces, which results in reduced mass flux compared to a comparable cross-section in a homogeneous solution. The decrease in mass flux is inversely proportional to diffusion accessible porosity [
Porosity is one of the most fundamental parameters describing porous media [
Porosity of sedimentary porous media is of great interest in many fields of research, e.g., in oil and natural gas extraction, in monitoring of contaminant percolation and in characterizing the dynamics of cracking and material failure. Porosity is defined as the ratio of the volume of pore space to the bulk volume of material and, for a saturated material, can be determined from knowledge of the quantity of fluid occupying the sample pore space. Traditional methods for core analysis are based on bulk measurement, which will average over any heterogeneity present in the sample [
New developments in science and technology cannot guarantee the future global energy demand that is expected to grow during the next 20 years; a more realistic solution lies in sustaining and increasing production from existing fields, the vast majority in fractured carbonate reservoirs. Therefore, it is necessary to better understand fluid flow mechanisms in reservoir system in order to achieve optimum recovery.
A significant percentage of oil and gas reserves are trapped in fractured carbonate reservoirs―more than 60 percent of the world’s proven oil reserves, and 40 percent of its gas reserves. While increasing oil and gas production from carbonate reservoirs may not be the only solution to meeting forecast energy demand, it is clear that these reservoirs will play an increasingly important role in the future of our industry.
Carbonate reservoirs are considered to be extremely challenging in terms of accurate recovery prediction because of their complexity and heterogeneity. Most carbonate reservoirs are naturally fractured and contain fractures that can range from isolated microscopic fissures to kilometer-wide collections called fracture swarms or corridors. These fractures create complex paths for fluid movement which impact reservoir characterization, and ultimately, production performance and total recovery [
Naturally fractured reservoirs present many challenges. The uncertainties related to the size of the physical structure and the reservoir fluid content, make understanding fluid flow unpredictable. In this work, we used some techniques to determine the fracture properties for understanding the reservoir and its fluid flow mechanisms [
Asphaltene is a fraction of petroleum crude materials conventionally defined as the fraction insoluble in n-heptane but soluble in toluene [
The aim of this work is to characterise cores from a naturally fractured porous media and to determine the permeability property to determine the crude oil sorption behaviour.
The ki (intrinsic permeability) dimensions are (L2), or area. The relationship between hydraulic conductivity and intrinsic permeability is Equation (1):
k = k i ( ( ρ w * g ) / μ w ) (1)
where ρ w is the water density, g is the acceleration of gravity and μ w is the water viscosity.
Units for k i can be square feet, square meters, or square centimetres. In the petroleum industry, the darcy is used as a unit of intrinsic permeability, (the petroleum engineer is similarly concerned with the occurrence and movement of fluids through porous media). Both the viscosity and the density of a fluid are functions of its temperature. The viscosity increases with decreasing fluid temperature [
The naturally fractured media were collected from reserves in Campeche City, Mexico. The materials were collected into polyethylene bags and transported to the Instituto Nacional de Investigaciones Nucleares (ININ) laboratory. The samples were cut from a limestone outcrop boulder collected near Campeche México. The core has vuggy porosity which can be observed from its surface and size,
The vugg sizes were determined to be 1.4 - 11.4 mm. It is observed from surface photos that there are several regions. Nute colored regions in the sample correspond to the matrix. The collected samples were cut into small pieces and analyze by several techniques,
When the material was cut, organic material remains from the pores. The vuggs in dark color contain organic material which was analyzed. These samples were used in the experiments too,
With respect to the bulk.
Scanning Electron Microscopy (SEM) was used to study the morphology of the matrix of carbonates cores [
An X-ray diffraction analysis was performed for the samples [
The infrared analysis was performed with solid samples using a Nicolette 550 IR spectrophotometer with the KBr disc method [
With respect to the surface
Specific surface (As, m2g−1) were determined for both dry and degassed natural materials using a multipoint N2 adsorption/desorption Brunauer-Emmett-Teller (BET) method at room temperature in a Micromeritics Gemini 2360 surface area analyzer.
The bitumen remains from the nute core with vuggs, porous system, were examined by SEM too in order to verify the absence or presence of carbon and sulphur like main components of the bitumen.
Water displacement within cores is presented. This system was built with two pieces from core wet material simulating a natural vuggy fractured porous medium. The time and water volume were determined.
The porosity of a rock is the percentage of pore space. The samples were oven at 65˚C and weighed daily until a constant mass was achieved. The final mass was recorded as the dry mass in air. The samples were then completely saturated with water and again weighed first in air and then while submerged in water. The porosity for each sample was determined as the ratio of the volume occupied by water at full saturation (Vw) to the volume of sample (Vs). Since the density of water is approximately equal to 1 g/mL, porosity was calculated for each sample as Equation (2) [
Porosity ( n ) = V w / V s × 1 00 % (2)
where:
V w = volume of voids and pores.
V s = total (bulk) volume of the rock.
Permeability in oil-bearing rocks indicates the relative ease with which oil will flow through the rock. Most sandstone is very permeable; granites have extremely low permeabilities and may be impermeable for practical purposes. Limestones can vary greatly from low permeability in a hard, well-cemented limestone without much porosity (like some of the British Carboniferous Limestone) to high permeability in a porous oolite (such as the Portland Stone).
In terms of petroleum geology, permeability is usually measured in millidarcies. The term “darcy” comes from water supply or hydrogeological studies based on the work of Henry Darcy [
Technically, a darcy is “the permeability that will allow a flow of 1 cubic centimeter per second of a fluid with 1 centipoise viscosity (resistance to flow) through a distance of 1 centimeter through an area of 1 square centimeter under a differential pressure of 1 atmosphere”.
With respect to the bulk.
The cores from naturally fractured media considered in this work were nute and gray colours. The SEM images 20, 95, 100 and 250 magnifications for naturally fractured media are shown in
In the first case, low magnifications of material showed particles with both smooth and rough surfaces. Some stress lines can be observed. In these figures can be observed that the surface is mainly compacting with porous with several sizes. Some crystals appear in preferential zones mainly composed by calcium, carbon and oxygen. Apparently into free spaces were found the organic materials, organic residues of crude oil. From observation of these micrographs, it is apparent that the material has a porous structure with a large surface area, as will be discussed later.
In conjunction with electron microscopy, elemental chemical composition was determined. The identifications of surface features were performed by qualitative EDS analyses. The EDS results are: carbon (35%), oxygen (33%), magnesium (0.23%), aluminium (0.74%), silicium (0.18%), sulfur (1.42%) and calcium (30%),
The crude oil residue was analyzed using LV-SEM. The crude oil residue morphology is shown in
(4%) and calcium (2%).
According to the Joint Committee on Powder Diffraction Standard (JCPDS, cards No. 85-1108 (porous core) and No. 85-0849 (solid core) [
FTIR spectra (4000 cm−1 to 400 cm−1) of oil nucleus shows naturally fractured media show that both studied materials has the vibrational frequencies similar, the band at 3432 cm−1 is for O-H stretching, at 1800 cm−1, 1422 - 1429 cm−1 and 875 cm−1 bands are vibrations representatives of carbonates group.
With respect to the surface
The specific area and other surface properties for the cores by the BET method are shown in
The porosity of a rock is the percentage of pore space. The results of this deter
| Parameters | Porous core | Solid core |
|---|---|---|
| Surface area, m2/g | 1.4966 | 0.0732 |
| Total pore volumen, cm3/g | 6.575e−04 | 2.348e−03 |
| Vm, cm3 (STP)/g | 0.3439 | 0.0168 |
| Porous diameter, nm | 1.7573 | 128.29 |
| Material | Porosity,% | ki, cm2 | k, cm/s |
|---|---|---|---|
| Porous core | 26 | 2.5 × 10−9 | 2.23 × 10−4 |
| Solid core | 8.5 | 11.24 × 10−5 | 10.01 |
Marica et al., 2006: Porosity, % 9.3, 20.8, 22.8, 22.9, 25
mination are shown in
The studied materials have porous microstructures with similar elemental composition. The calcium carbonate is the main inorganic compound present in both cores according XRD. All the techniques used confirmed that the main composition is of carbonate nuclei. The porosity and permeability of natural vuggy fractured porous medium from core samples was determined obtained in the laboratory with conventional procedures. The values obtained show that the cores have permeability where the fluid migrates through the particles at 2.23 × 10−4 cm/s.
This work has been partially supported by ABACUS, CONACyT (Mexico) grant EDOMEX-2011-C01-165873. Thanks to Dr. Abraham Medina Ovando from Instituto Politécnico Nacional for the cores to analyzed.
Romero-Guzmán, E.T., Reyes-Gutiérrez, L.R., Klapp, J. and Hernández-Mendoza, H. (2018) Characterization of Natural Vuggy Fractured Porous Medium: Its Physicochemical Properties, Porosity and Permeability. Journal of Minerals and Materials Characterization and Engineering, 6, 38-49. https://doi.org/10.4236/jmmce.2018.61004