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Carbonate reservoirs have a very important role in oil and gas production in the world and generally, it comes from reef carbonates. Many were found in the Silur-Devonian, Cretaceous, and Neogene well. The majority of the carbonate reservoir rock has been facing changes in the primary pores because of the diagenesis processes. The diagenetic process causes some changes in the composition of the organic material inside the rock. Therefore, during the diagenetic process physical, chemical, and microbiological. In this paper, the hopane series biomarker analysis was used on the reef carbonate samples at several boreholes, namely B1-2, B3, and B4-5 in the Tikehau area, Tuamotu Islands in order to prove the presence of hydrocarbons and the effect of diagenesis. The gas chromatogram experiment results show a smooth and "gaussian" trend line due to the presence of iso- and anteiso-alkanes in the C25-C35 range. Except that, the stable configuration of the hopane biomarker is 17(H)α, 21(H)β. Then it can be concluded that the reef carbonate has undergone a maturation process due to high temperatures, namely the initial diagenesis process with the presence of abundant non-aromatic hydrocarbon compounds and n-alkane compounds from the area. [ABSTRACT FROM AUTHOR]

In this paper, the authors conducted a study aimed at determining the degree of influence of reservoir temperature on the reaction rate of hydrochloric acid with reservoir rocks in order to improve the technologies for various geological and technical measures aimed at increasing well productivity. Based on various laboratory and practical experiments, it has been established that when acid interacts with a polymer, there is a noticeable increase in the penetration depth of the composition, which ultimately affects the effectiveness of the implementation of channels through which liquid hydrocarbons will be filtered. For non-acidic components, their interaction with other types of acids is considered due to the search for the optimal composition to increase the permeability of the bottomhole formation zone. Based on the results obtained, recommendations are given regarding the use of various modified formulations in improving technical and technological approaches to processing the bottomhole zone of formations. [ABSTRACT FROM AUTHOR]

The build-up of pressure on conversion of kerogen to hydrocarbons is a widely recognized phenomenon in oil and gas generation. During kerogen transformation, hydrocarbon production is frequently accompanied by an increase in volume. The generation of hydrocarbons leads to higher pressures within the source rock causing the fluids to expel out of the source rocks and migrate upwards into shallow reservoirs. The capture of the fluid exodus along the migration pathways owing to pressure differences between over pressured source and reservoir rocks catalyzes hydrocarbon entrapment where favorable geological trapping conditions prevail. However, where such avenues are denied, the source rocks themselves become the site for hydrocarbon accumulation at overpressures. The source rocks of Salym field in West Siberian Basin are one such typical example of hydrocarbon generation, in situ pore pressure generation and retention. A geological model has been conceived to explain the mechanism involved based on P-T conditions of the reservoirs in Bazhenov and Achimov Formations and application of fundamental fracture mechanics. [ABSTRACT FROM AUTHOR]

This article presents the experimental results of studies the mechanical and filtration properties of rocks in the Verkhnevilyuchanskoye oil and gas field, carried out on the unique Triaxial Independent Load Test System (TILTS) of the Institute for Problems in Mechanics of the Russian Academy of Sciences. The methodology of conducting experiments on the TILTS facility for studying elastic and strength characteristics of rocks is described. On the basis of analysis of the results of triaxial tests the elastic characteristics of the samples were obtained: Young's modulus and Poisson's coefficient. The strength characteristics of the studied rocks were determined based on the Coulomb-More theory: coupling modulus and internal friction angle. The permeability evolution dependences during loading of the samples have been obtained. The analysis of experimentally obtained mechanical properties of rocks for mutually orthogonal directions in the rock is carried out. [ABSTRACT FROM AUTHOR]

Tight carbonate reservoir is located in North Kuwait and classified as an unconventional reservoir under study. A practical imaging technique of wettability contact angle (θ°) presents "big data as well as relative-permeability (Krw and Kro) measurements. Also, modeling, through rock image technology, the vast well-documented grain/ pore boundary morphology available inside fresh rock fragments. Conventional laboratory relative-permeability experiments are expensive and time consuming. This study will introduce a novel method to measure/ calculate relative permeability through fast, less expensive, non-destructive, and environmentally friendly techniques of imaging technology. One tight carbonate reservoir is selected, imaged, processed, analyzed, and then modeled using several pore diameter morphological models. The images are captured using backscattered electron microscopy BSE-SEM technology analyses. In this study, two dimensional images are used to characterize the morphology of selected samples grains and pores, using two-step technique process. In the first step, the image is captured using backscattered electron detector (BSE), digital electron microscopy imaging, and pore counting processing technology. All of sample grain/ pore features captured in the image are reported in micrometer units. In the second step, the pore area of such features is scanned using image analysis software that can accurately measure several morphological parameters of pore and grain spaces. A robust technique of visual estimate is used, which has the advantage of speeding the image analysis process. The visual analysis software tool counts different pores and grains and measures their shapes and sizes that are crucial for relative-permeability calculations. Several pore morphological models have been considered for optimum accuracy comparisons, including pore/ grain relationships (Area/ Perimeter), pore contact angle (θ), and pore count. Relative permeability is calculated based on area of the pore/grain features measured from two-dimensional images. The study objectives are to accurately measure Wettability contact angle of huge pore geometries using 2D image technology. Also, to understand the nature of the pore network in the candidate reservoir. To study relative permeability action of internal influences of pore and grain morphology needed for EOR/ IOR future programs. And, finally, to measure relative permeability faster and more accurately. [ABSTRACT FROM AUTHOR]

Xanthan gum and polyacrylamide are polymer types that are widely used in petroleum operations such as polymer flooding. Polymer flooding it is used to reduce the mobility of the injection water by increasing the viscosity or viscosity of the water. With the lower mobility injection fluid, it is expected to increase the oil recovery. Another thing that needs to be considered in polymer flooding is adsorption. When the polymer solution flowing through a porous medium (reservoir), there is an interaction between the polymer particles and the surface of the reservoir rock pores. The interaction known as polymer adsorption causes some of the polymers in solution to bond to the surface of the pore walls. This can reduce the amount of polymer so that the required concentration is higher to get a good mobility ratio which means it can reduce the economic level. The purpose of this study was to analyze the characteristics of xanthan gum and polyacrylamide polymers. These characteristics include compatibility and viscosity tests at several salinities. In addition, the adsorption was also analyzed based on the type and concentration of polymer in the 40 Mesh and 100 Mesh sand grains. Based on the experimental results, it was found that all polymer solutions used, both xanthan gum and polyacrylamide, were compatible with variations in the salinity of formation water. Viscosity increases with increasing concentration, but viscosity tends to decrease with increasing salinity. The test showed that the adsorption was directly proportional to the concentration and polyacrylamide showed a higher adsorption rate than xanthan. In addition, it was found that the adsorption was greater in large sand (40 mesh) than in small grains (100 mesh). [ABSTRACT FROM AUTHOR]

Dual-energy CT scanning is not a novel method for evaluating reservoir rock. It has been used for many years. Each time the rock is scanned with a different X-ray energy, the same region is scanned twice. Dual energy scanning is successfully used in investigations of fluid flow visualization. Along with the lack of appropriate software and procedures for generating mass density and nuclei count pictures from high and low energy CT data, the added problem is the absence of processes for characterising the cores using density and atomic numbers. The density and atomic number images can now be generated from the dual-energy data using commercially available software. Several strategies are described in this work to better characterize reservoir rocks using density and atomic number data. Small plug samples with known petrophysical parameters were first used to validate the process. A 60-foot-long core section was scanned with two different X-ray energies CT scans every five centimetres (2 inches) from an Upper Jurassic carbonate reservoir in Saudi Arabia. Qualitatively, the results were interesting and could help us better understand carbonates. To calculate porosity values using approximate mineral compositions, this document provides step-by-step directions in the form of diagrams. [ABSTRACT FROM AUTHOR]

The Alkali-Surfactant-Polymer (ASP) flooding is one technique of Enhanced Oil Recovery (EOR). The ASP injection mechanism reduces the interfacial tension (IFT) between fluids as well as fluids and the rock surface. Further, ASP modifies the wettability of the rocks toward water-wet environment. Hence the oil phase can be transferred to the producer. In practice, one of ASP problems in the reservoir rock is the adsorption process of ions on the rock surface. High adsorption decreases the performance of the ASP treatment includes more minor IFT reduction and less wettability alteration. As an Alkali, Sodium Carbonate (Na2CO3) is very effective in reducing surfactant adsorption. However, this type of Alkali consumes a huge of raw material. 105g Sodium Carbonate provides 1 mole of alkalinity. The addition of Ammonium Hydroxide (NH4OH) in ASP sodium carbonate scheme is considered improve the efficiency. Ammonium Hydroxide (NH4OH) provides alkalinity of 1 mole from only 17g of raw material. The synergy of two alkalis can supply bigger alkalinity from the standard ASP technique with the inherent logistical advantages as well. This concept has known as a hybrid-alkali concept. The model has an inverted five spot pattern injection system, two layers of a sandstone formation, and is bordered by shale. [ABSTRACT FROM AUTHOR]

Permeability prediction in carbonate rock reservoirs is a very complex task in reservoir characterization due to the heterogeneity of carbonate reservoir rock. Thus, accurate predicting for permeability needs a good understanding of reservoir heterogeneity. The best method to do this is by classifying reservoir rock into groups that is latterly and vertically similar in petrophysical properties to give a unique relationship between porosity and permeability. Cluster Analysis method is used to classify the rock types of tertiary reservoir in Khabaz oil field, to understand the heterogeneity of reservoir by analyses conventional well logs data, four rock types were identified; each group is proportional to a unique hydraulic flow unit which is a reservoir layer that is horzantally and vertically same flow and bedding characteristics. Core data also classified into four groups by Flow Zone Indicator (FZI) method and permeability equations determined for each group with a high (R2) value than making a relationship for all data. The four permeability equations were linked with four rock type to predict permeability in un - cored wells and intervals by using porosity data from logs, either permeability predicted by using the classical method. the comparison between two approaches, the highest correlation coefficient is given by FZI method, so integrating Rock types with FZI method gives the best technique to predict permeability in heterogynous carbonate reservoirs. [ABSTRACT FROM AUTHOR]

This article considers different methods for near-wellbore monitoring using acoustic waves. According to the first method, the initial wave signal is created at a certain distance from the surveyed area and transmitted through the well. Thus, the "echo" of the signal reflected from the permeable area will carry information about the reservoir characteristics of this area. According to the second method, the source and receivers of acoustic signals are located directly in the surveyed area of the well. The quantitative and qualitative features of the wave dynamics depending on the state of the porous medium have been determined. As a result, the reservoir rock characteristics significantly affect the evolution of acoustic signals. This makes possible to use acoustic methods to monitor near-wellbore areas. [ABSTRACT FROM AUTHOR]

The oil and gas are usually trapped inside the reservoir rock pores such as Limestones or Sandstone. Most of the oil and gas companies use the common method for calculating rock total porosity by using Helium (He) or Nitrogen (Ni) gas. But this technique is limited only in total porosity information of the limestone, not the petrophysical properties of the sample. Another powerful technique that can be used to investigate the internal structure of the rock is Neutron Imaging (NI). Several experiments related to NI about porous rocks have been done by another researcher, but an experiment about the reservoir rock properties with NI has not been done. Porosities are one of the most important parameters to predict the availability of oil or gas. X-Ray Imaging (XRI) was describing perfectly these porosities, but again the XRI only provide porosities information of the limestone. To surpassing this limit, NI was employed. NI does not limit only to visualize the rock porosity but also can distinguish inhomogeneities materials inside the limestone. In this paper, the Limestone sample has been investigated by employing tomography methods of both XRI and NI technique. The total porosity from both technique then compared by the java petroleum systems databased (conventional method). From the experiment knew that the total porosity of the Limestone was about 28.4%, 34.36%, and 30% - 36% by an XRI, NI and conventional method respectively. XRI detected all porosity including a traped pores, channel pores / interparticle, Intercrystalline and Vugular pores. It was known that there were a lot of channel pores inside the sample which made the oil flow in the centre of the stone while the crude oil extracted by the oil company. On the other hand, NI gives more information about inhomogenous minerals inside the Limestone belongs to Dolomite, Aragonite, Calcite, Magnesite, Ankerite, and Siderite. [ABSTRACT FROM AUTHOR]

In order to mitigate the greenhouse gas emission level largely in the atmosphere the best possible solution is storing the CO2 in deep saline confined aquifers having impermeable caprock material on the top. However, such deep sedimentary rocks in the presence of water and brine saturation undergo degradation in their mechanical properties – elastic modulus and toughness. Therefore, it is very important to understand and quantify the degree of degradation of mechanical properties of those rocks under varied brine concentration. For this purpose, a detailed experimental work is carried out in this paper. The specimens are saturated under varying brine (0% NaCl to 30% NaCl) and water of different degree of saturation (0% DOS to 100% DOS) saturated sandstone and siltstone rocks, respectively. The rock samples namely, sandstone and siltstone material used in this work collected from Gosford, New South Wales and Eidsvold, Queensland, respectively in Australia. The mechanical properties, namely elastic modulus, E and fracture toughness, KIC estimated using Uniaxial Compressive Strength (UCS) and Three-Point Bending (TPB) tests, respectively. From the powdered X-ray diffraction (XRD) analysis, the sandstone material mineralogical composition has 65.5% quartz, 27.6% kaolinite, 5.4% montmorillonite and 1.4% anatase. Similarly, the siltstone material mineralogical composition has 35% quartz, 53% kaolinite, 8% muscovite, 3% alunite and 1% other minerals. [ABSTRACT FROM AUTHOR]

Comprehensive characterizarion methods are carried out to determine accurate source rock and reservoir identification. Geochemical data has become a critical part of recent unconventional exploration and development. However, due to high cost of geological core extraction and analysis, geophysical wireline logging tools have become the primary source of downhole measurement of geomechanical properties. This study covers an integrated approach at defining geochemical report derived from geological core extraction and analysis and its relationship with geophysical wireline logs of 5 (five) wells at Northeast Java Basin. Geophysical wireline logs can be utilized to identify reservoir and source rock intervals in the early stage of well drilling. However, the well logs that directly measure the hidrogen content of the kerogen do no exist. Consequently, it is utilized for source rock evaluations and calculation of Total Organic Carbon (TOC) which are most commonly include sonic, density, gamma ray, neutron, and resistivity. The Van Krevelen diagram has been applied to all 5 (five) wells that indicates 2 (two) of them have potential gas – kerogen type III/IV with marginally mature to mature source rock. The integration of well logs and geochemical data greatly improves the accuracy and understanding of the controls of reservoir quality and source rock. It can be used for further step of knowing basin potential and its prospect level. [ABSTRACT FROM AUTHOR]

In recent years, a large amount of proven reserves have been submitted in the Fuyu oil layer in the Qijia-Longxi area. Since the sedimentary environment of the Fuyu oil layer is the delta plain and the front margin subfacies, it is mainly a tight oil layer with a permeability of about 1.5 mD. The mineral composition, pores and throat geometry, size and distribution of the reservoir rocks and their interconnections are evaluated and analyzed. The results show that the reservoir rocks are fine, closely arranged, and the clay content is high. The porosity of the oil layer is mainly to reduce the intergranular pores, the face rate is low, the connectivity is poor, and the conventional water flooding development is difficult. The small throat radius is the main reason for the low seepage capacity of the reservoir. When the permeability is less than 1mD, the throat is mainly micro-throat and micro-throat with a radius of less than 1μm; when the permeability is 1~2mD, the throat is micro-throat The channel and the fine throat are dominant; as the permeability increases, the percentage of the movable fluid also increases, in logarithm relationship, the 1.0mD reservoir has a movable fluid of 41.4%, indicating that for dense reservoirs The water injection development is difficult, the movable fluid content is low, and the stable production is difficult. In this paper, the study on the pore structure and seepage characteristics of the Fuyu oil layer can be said to provide technical support for the optimization of the development methods of the pore medium reservoirs in different scales of the Fuyu oil layer. [ABSTRACT FROM AUTHOR]

Rock type and porosity characterization remain as the main challenges in a carbonate reservoir setting. Rock classification and permeability estimation have normally been done using the rock typing method. Unfortunately, the method utilizes core data, which are often not available and quite expensive. Therefore, there is another alternative using classifier method that cost of wells maintenance or hydrocarbons production may be lower than obtaining the required parameters through the core data process. This study uses two classifier methods, which are Naïve Bayes and the Random Forest method. Those classifier methods make a rock type classification model based on the best rock typing method, which is Lucia method, in the same field. The objective is comparing and choose the best method of those two classifiers. Several assessments are done in the comparing process. Random Forest method has a better result in estimating the error value of the training model, comparing the core permeability with predicted permeability, and the level of accuracy in predicting rock type classification. However, the Naive Bayes method has a separately well distribution of seismic parameters compared to the Random Forest method, which is the most important thing. Therefore, in wells that have no core data, we estimate the permeability value by using the Naive Bayes method. [ABSTRACT FROM AUTHOR]

The paper uses a mathematical model of hydraulic fracturing, obtained by the methods of the elastic filtration theory of oil-displacing fluid injected into the formation, which is a heterogeneous, fractured-porous medium. The rock formation undergoes elastoplastic destruction with the generation of cracks when the pressure difference in the fluid reaches a critical value. An increase in the volume of the system of fractures in the cracking zone leads to a decrease in the porosity of the blocks in accordance with the pore volume strain compatibility condition. Engineering formulas are obtained for the radius of cracking and crack opening. The flow rate of a well with a hydraulic fracture decreases over time. This phenomenon, which is also characteristic of carbonate formations with natural jointing, is explained by the increasing effect of capillary locking of the formation water accumulating near the walls of the cracks. Laboratory studies on the flat micromodel of the reservoir showed the possibility of restoring the well production rate with a fracture by injection of an acidic oil-displacing composition based on surfactants, inorganic acid adduct and polyhydric alcohol. The results of successful field tests of the composition on the Permian-Carboniferous deposit of high-viscosity oil from the Usinsk oilfield with fractured-porous reservoir rock are presented. [ABSTRACT FROM AUTHOR]

The oil-wet core samples from wells of the Usinskoye oilfield are investigated by a combination of methods. The elemental (mineralogical) composition of the samples is determined via X-ray diffraction and X-ray fluorescence analysis. The content of organic matter in the natural core material is determined by the method of continuous extraction using a Soxhlet apparatus. Wettability of the reservoir core samples from the Permo-Carboniferous deposit of the Usinskoye oilfield is determined by two independent methods. A contact angle of 89° upon the selective wetting of core surface has been determined by the capillary absorption method and calculated by Juren formula. [ABSTRACT FROM AUTHOR]

Presented are the results of laboratory studies on the effect of electrolytes on physicochemical properties of the oil-displacing acid systems based on surfactants, coordinating solvents and complex compounds. It has been found that addition of AlCl3, FeCl3, FeCl2 and MgCl2 electrolytes decreases pH values and increases density and viscosity of the solutions. It enables to control in a wide range physicochemical properties of the systems and their effect on reservoir permeability. [ABSTRACT FROM AUTHOR]

Carbonate rocks store more than 50% of world's petroleum. These rocks' structures are highly complex and vary depending on many factors regarding their formation, e.g., lithification and diagenesis. In order to perform an effective extraction of petroleum it is necessary to know petrophysical parameters, such as total porosity, pore size and permeability of the reservoir rocks. Carbonate rocks usually have a range of pore sizes that goes from nanometers to meters or even dozen of meters. The nanopores and micropores might play an important role in the pores connectivity of carbonate rocks. X-ray computed tomography (CT) has been widely used to analyze petrophysical parameters in recent years. This technique has the capability to generate 2D images of the samples' inner structure and also allows the 3D reconstruction of the actual analyzed volume. CT is a powerful technique, but its results depend on the spatial resolution of the generated image. Spatial resolution is a measurement parameter that indicates the smallest object that can be detected. There are great difficulties to generate images with nanoscale resolution (nanotomographic images). In this work three carbonate rocks, one dolomite and two limestones (that will be called limestone A and limestone B) were analyzed by nanotomography. The measurements were performed with the SkyScan2011 nanotomograph, operated at 60 kV and 200 ?? to measure the dolomite sample and 40 kV and 200 ?? to measure the limestone samples. Each sample was measured with a given spatial resolution (270 nm for the dolomite sample, 360 nm for limestone A and 450 nm for limestone B). The achieved results for total porosity were: 3.09 % for dolomite, 0.65% for limestone A and 3.74% for limestone B. This paper reports the difficulties to acquire nanotomographic images and further analysis about the samples' pore sizes. [ABSTRACT FROM AUTHOR]

Estimation of recoverable reservoir reserve should be as accurate as possible. Detailed reservoir parameter estimation is needed to ensure good estimate. Many uncertainties exist in recovery estimation due to reservoir rock properties such as permeability and porosity. The estimate of such parameters may change with the available observations and time. This paper reports the use of Bayesian ensemble Kalman filter (EnKF) to estimate the permeability. It is a method in which a sample of state are generated and updated sequentially. Two simulated experiments are presented to investigate the applicability of EnKF. The first concern is using EnKF for parameter estimation in reservoir models such as line source, bounded reservoir, 1D flow numerical model. The second concern is using EnKF in one dimensional two interacting wells. The solutions are derived analytically. The state consists of the parameters and the analytical solution. The estimation process consists of two steps: forecast and update. Forecast step is calculated by using forward function which can be analytical or numerical solution. Update step uses Kalman filter scheme where the gain is calculated from sample covariance. Asymptotic studies as the basis for the validity of EnKF is well established and summarized in this report. The study concludes that EnKF can provide satisfactory results for reservoir reserve parameter estimation. Parameter estimation for reservoir simulation is an important future issue in order to improve the forecast. [ABSTRACT FROM AUTHOR]

In most geothermal reservoirs, cracks are considered very important because of the ability to transport water vapor. In most cases, characterizations of cracks are often difficult to be performed. However, through the vast development of imaging technique, many researches have been conducted in order to obtain better understanding regarding the nature of cracks. Using micro-CT (μCT) scanning devices, i.e., the Skyscan 1173, we were able to obtain 3D images of geothermal reservoir rock from West Java. The rock sample was scanned using X-ray voltage of 130 kV and current of 61 μA. The reconstructed images have spatial resolution of 59.85 μm/pixel. Using CTVox and ImageViewer, we were able to visualize the cracks both in 2D and 3D perspective. We further performed image processing and analysis, i.e.: simple segmentation of pore-solid by thresholding the gray values and binarizing the images, de-noising (despeckling), and 3D structure analysis. From these analyses, we obtain the value of porosity of 6.27%, and from further analysis, we separate the crack from the granular pore. The fraction of the cracks is 2.35% from the total volume of the sample. This preliminary study however, still contains some errors. By visualizing the produced image from the isolation, we can still observed the existence of isolated granular pores. Nonetheless, this study has confirmed that using image processing and image analysis approach of reconstructed μCT images, we were able to isolate cracks from granular pores, and also calculate the volume fraction of the cracks. [ABSTRACT FROM AUTHOR]

When hydrocarbons accumulate in reservoirs, the reservoir rocks and a large volume of rock associated with the reservoirs undergo resistance changes. This method relates generally to the field of geophysical prospecting for the purposes of hydrocarbon exploration, development, and production. This method includes measuring magnetic field gradient in at least two orthogonal directions in response to the induced electromagnetic field and determining an electric field response. Specifically, this method is a method for determining the difference between the electrical resistance of a reservoir at an initial time and its electrical resistance at one or more later times, and relating that difference to production of hydrocarbons from the reservoir during the interim period. Electromagnetic methods are now being used to provide images of subsurface resistance on the reservoir scale. These images provide for the first time observation of the distribution of porosity and fluid content on the same scale as the reservoir. They are being used to identify bypassed oil, monitor sweep efficiency, identify unanticipated breakthrough, and map features. All such information could previously only be inferred from measurements within the well or from production data from the well. For monitoring production and enhanced recovery processes, when it can be assumed that the porosity is essentially constant and when there is a resistivity contrast in the different fluids or phases involved, the imaged resistivity is a direct mapping of the changes in saturation. In this paper we discuss about the methods for electromagnetic measurement methods and its application in oil and gas industry. [ABSTRACT FROM AUTHOR]

The porous systems of reservoir rocks present a complex geometry, involving aspects of shape of pores (morphology) and connectivity between the pores (topology). The macroscopic physical properties of these materials are strongly dependent of their microstructures. Based on these aspects, the present study has as main objective the characterization of the porous system geometry and computational determination of petrophysics properties of carbonate reservoir rocks through the X-ray microtomography methodology. Samples were microtomographed with the microtomographs Skyscan model 1172, installed at the PETROBRAS Research and Development Center (CENPES), Rio de Janeiro-RJ, Brazil and model 1173, installed at Sedimentary Geology Laboratory (LAGESD) in the Federal University of Rio de Janeiro (UFRJ). Two samples of carbonates were measured, Travertine and Dolomite, with spatial resolutions of 7 μm and 9.8 μm and 1.3 μm, 7 μm and 17 μm, respectively for the travertine and dolomite. With the data collected in the acquisitions, 900 transversal sections were reconstructed for each one of the referred resolutions. For the sample of dolomite, the average porosity found was 21.64%, 20.92% and 15.97% for resolutions of 1.3 μm, 7 μm and 17 μm, respectively. For the sample of travertine, the average porosity was 7.80 % and 7.52 % for resolutions of 7 μm and 9.8 μm, respectively. For the sample of dolomite, the pore size distribution showed that 50 % of the porous phase has pores with radius up to 37.6 μm, 84.6 μm and 84.4 μm, for the spatial resolutions of 1.3 μm, 7 μm and 17 μm, respectively. For the sample of travertine, 50 % of the pores have radius up to 148.1 μm and 158.1 μm, for the spatial resolutions of 7 μm and 9.8 μm. [ABSTRACT FROM AUTHOR]