scholarly journals New Method of Oil Reservoir Rock Heterogeneity Quantitative Estimation from X-ray MCT Data

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 5103
Author(s):  
Irena Viktorovna Yazynina ◽  
Evgeny Vladimirovich Shelyago ◽  
Andrey Andreevich Abrosimov ◽  
Vladimir Stanislavovich Yakushev
Keyword(s):  
Quantitative Estimation ◽  
Pore Space ◽  
Core Sample ◽  
New Method ◽  
Reservoir Rock ◽  
Core Material ◽  
Oil Reservoir ◽  
Pore Scale ◽  
X Ray ◽  
Rock Heterogeneity

This paper considers a new method for “pore scale” oil reservoir rock quantitative estimation. The method is based on core sample X-ray tomography data analysis and can be directly used to both classify rocks by heterogeneity and assess representativeness of the core material collection. The proposed heterogeneity criteria consider the heterogeneity of pore size and heterogeneity of pore arrangement in the sample void and can thus be related to the drainage effectiveness. The classification of rocks by heterogeneity at the pore scale is also proposed when choosing a reservoir engineering method and may help us to find formations that are similar at pore scale. We analyzed a set of reservoir rocks of different lithologies using the new method that considers only tomographic images and clearly distributes samples over the structure of their pore space.

scholarly journals Pore-Scale Imaging of the Oil Cluster Dynamic during Drainage and Imbibition Using In Situ X-Ray Microtomography

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-13 ◽  
Author(s):  
Junjian Li ◽  
Yajun Gao ◽  
Hanqiao Jiang ◽  
Yang Liu ◽  
Hu Dong
Keyword(s):  
Specific Surface ◽  
Capillary Pressure ◽  
Surface Area ◽  
Specific Surface Area ◽  
Pore Space ◽  
Relative Volume ◽  
Pore Scale ◽  
X Ray ◽  
Cluster Dynamic ◽  
Remaining Oil

We imaged water-wet and oil-wet sandstones under two-phase flow conditions for different flooding states by means of X-ray computed microtomography (μCT) with a spatial resolution of 2.1 μm/pixel. We systematically study pore-scale trapping of the nonwetting phase as well as size and distribution of its connected clusters and disconnected globules. We found a lower Sor, 19.8%, for the oil-wet plug than for water-wet plug (25.2%). Approximate power-law distributions of the water and oil cluster sizes were observed in the pore space. Besides, the τ value of the wetting phase gradually decreased and the nonwetting phase gradually increased during the core-flood experiment. The remaining oil has been divided into five categories; we explored the pore fluid occupancies and studied size and distribution of the five types of trapped oil clusters during different drainage stage. The result shows that only the relative volume of the clustered oil is reduced, and the other four types of remaining oil all increased. Pore structure, wettability, and its connectivity have a significant effect on the trapped oil distribution. In the water sandstone, the trapped oil tends to occupy the center of the larger pores during the water imbibition process, leading to a stable specific surface area and a gradually decreasing oil capillary pressure. Meanwhile, in oil-wet sandstone, the trapped oil blobs that tend to occupy the pores corner and attach to the walls of the pores have a large specific surface area, and the change of the oil capillary pressure was not obvious. These results have revealed the well-known complexity of multiphase flow in rocks and preliminarily show the pore-level displacement physics of the process.

Interrelation of Crude Oil and Rock Properties With the Recovery of Oil by Caustic Waterflooding

1977 ◽  
Vol 17 (04) ◽  
pp. 263-270 ◽  
Author(s):  
Robert Ehrlich ◽  
Robert J. Wygal
Keyword(s):  
Crude Oil ◽  
Reservoir Rock ◽  
Rock Properties ◽  
Core Material ◽  
Crude Oils ◽  
Active Materials ◽  
Interfacial Tensions ◽  
X Ray ◽  
Recovery Mechanisms ◽  
Surface Active

Abstract This paper describes a series of laboratory caustic (NaOH) waterfloods and related measurements using crude oils from 19 oil reservoirs. These were light (mostly,>30 degrees API) crudes mainly from South Louisiana and Texas, although crude oils from other areas also were tested. The waterfloods held core material (Berea sandstone), connate water (2-percent-NaCl brine) and other conditions (temperature, flow rate, aging time before flood) constant, and determined increased production due to NaOH injection for each crude oil. Relative permeability end-points before and after flooding were used to estimate initial and final wettabilities and, together with crude-oil acid numbers and interfacial tensions against NaOH solution, to infer the probable mechanism by which increased recovery was obtained. A series of laboratory NaOH depletion measurements by static and dynamic methods in core material from several oil-producing formations and in Berea sandstone is also described. Results are compared with those from similar measurements using pure clays and other minerals and with X-ray diffraction analysis of the core material. The following are observations from these tests.Crude oils with acid numbers greater than about 0.1 to a 0.2 mg KOH per gm of oil or interfacial tension against 0.1 percent NaOH less than about 0.5 dyne/cm gave significant caustic-waterflood increased production. There was no further correlation of increased production at higher acid numbers or lower interfacial tensions nor was there a correlation with the apparent initial rock wettability.Regardless of initial wettability or increased production, the cores are indicated to be water-wet production, the cores are indicated to be water-wet following NaOH waterflooding to a high water-oil ratio (WOR).Caustic consumption by reservoir rock is predictable from the formation mineral composition predictable from the formation mineral composition as determined by X-ray methods. Exceptions are noted where clay content is high and where trace amounts of gypsum are present. Introduction Crude oils containing naturally occurring organic acids will react with aqueous caustic solution to produce surface-active materials. These surfactants, produce surface-active materials. These surfactants, when generated during a caustic waterflood, can improve oil recovery over that of a normal waterflood by a number of mechanisms related to changes occurring at the oil-water and liquid-solid interfaces: interfacial-tension lowering, wettability change, changes in interface rheology, etc. The extent to which any of these mechanisms will be operative and the recovery improvement obtainable depends on, among other things, the amount and type of acids present, the initial formation wettability, the reservoir-rock pore geometry, and the extent to which it consumes caustic. The available literature describing mechanisms proposed for caustic-waterflooding improved recovery, proposed for caustic-waterflooding improved recovery, the conditions required for applicability, and the results of various laboratory and field studies have been surveyed most recently by Johnson. Some common currents of thought or implication in this literature and some common areas of uncertainty related to the effects of crude oil and reservoir rock properties on recovery mechanisms are listed below. properties on recovery mechanisms are listed below.The presence of acids in crude oil at some minimum level is an obvious necessary condition for improved recovery. Where emulsification is involved, minimum acid numbers ranging from 0.5 to 1.5 mg KOH per gm of oil have been suggested. No minimum has been stated for other recovery mechanisms. One might not expect such minimum requirements to be absolute since the quality of surfactants generated from these acids can vary widely among crude oils.Improved recovery by wettability alteration generally has been discussed in terms of a reversal from oil-wet to water-wet or vice versa. It has been implied that wettability reversal is required since capillary forces trapping oil are eliminated as the neutral wettability condition is traversed. SPEJ P. 263

scholarly journals Influence of zeolitization on the migration of reservoir fluids on the example of jurassic and neocomian deposits (Yamal oil and gas region)

2021 ◽  
Vol 21 (2) ◽  
pp. 88-92
Author(s):  
Elena P. Osipova ◽  
◽  
Angela G. Astarkina ◽  
Sergey V. Astarkin ◽  
Daniil A. Strelnikov ◽  
...  
Keyword(s):  
Crystal Structure ◽  
Gas Chromatography ◽  
Mineral Composition ◽  
Oil And Gas ◽  
Pore Space ◽  
Core Material ◽  
X Ray ◽  
The Core ◽  
Core Samples ◽  
Geochemical Studies

To assess the influence of zeolite group minerals on the migration of reservoir fluids in terrigenous deposits, complex (X-ray and gas-geochemical) studies of core material in the Yamal oil and gas region field were conducted. 54 core samples from the Pyakyakhinsky and Yuzhno-Messoyakhsky deposits were studied including 43 zeolitized and 11 non-zeolitized samples. The core samples were studied by gas chromatography to determine the content of hydrocarbons adsorbed in the pore space of the core, as well as by X-ray diffractometry to determine the mineral composition of the samples under study. The regularities of hydrocarbons distribution in the studied samples depending on the degree of their zeolization are established. The differences in the distribution of hydrocarbons in zeolitized and non-zeolitized siltstones have their own explanation. Having an ordered crystal structure and a certain size of the entrance windows zeolites are able to sorb.

Generation of ground truth images to validate micro-CT image-processing pipelines

2018 ◽  
Vol 37 (6) ◽  
pp. 412-420 ◽  
Author(s):  
Steffen Berg ◽  
Nishank Saxena ◽  
Majeed Shaik ◽  
Chaitanya Pradhan
Keyword(s):  
Pore Space ◽  
Ground Truth ◽  
Fluid Distribution ◽  
Micro Ct ◽  
Pore Scale ◽  
Binary Images ◽  
Rock Heterogeneity ◽  
Wide Range ◽  
Machine Learning Approach ◽  
Subsurface Engineering

Digital rock technology and pore-scale physics have become increasingly relevant topics in a wide range of porous media with important applications in subsurface engineering. This technology relies heavily on images of pore space and pore-level fluid distribution determined by X-ray microcomputed tomography (micro-CT). Digital images of pore space (or pore-scale fluid distribution) are typically obtained as gray-level images that first need to be processed and segmented to obtain the binary images that uniquely represent rock and pore (including fluid phases). This processing step is not trivial. Rock complexity, image quality, noise, and other artifacts prohibit the use of a standard processing workflow. Instead, an array of strategies of increasing sophistication has been developed. Typical processing pipelines consist of filtering, segmentation, and postprocessing steps. For each step, various choices and different options exist. This makes selection and validation of an optimum processing pipeline difficult. Using Darcy-scale quantities as a benchmark is not a good option because of rock heterogeneity and different scales of observation. Here, we present a conceptual workflow where noisy images are derived from a ground truth by systematically including typical image artifacts and noise. Artifacts and noise are not simply added to the images. Instead, tomographic forward projection and reconstruction steps are used to incorporate the artifacts in a physically correct way. A proof of concept of this workflow is demonstrated by comparing seven different image-segmentation pipelines ranging from absolute thresholding to a machine-learning approach (Trainable Weka Segmentation). The Trainable Weka Segmentation showed the best performance of the tested methods.

Permeability Upscaling for Carbonates From the Pore Scale by Use of Multiscale X-Ray-CT Images

2013 ◽  
Vol 16 (04) ◽  
pp. 353-368 ◽  
Author(s):  
A.. Dehghan Khalili ◽  
J.-Y.. -Y. Arns ◽  
F.. Hussain ◽  
Y.. Cinar ◽  
W.V.. V. Pinczewski ◽  
...  
Keyword(s):  
High Resolution ◽  
Error Bounds ◽  
Pore Space ◽  
Ct Images ◽  
Field Of View ◽  
Fine Scale ◽  
Pore Scale ◽  
Low Resolution ◽  
Coarse Scale ◽  
X Ray

Summary High-resolution X-ray-computed-tomography (CT) images are increasingly used to numerically derive petrophysical properties of interest at the pore scale—in particular, effective permeability. Current micro-X-ray-CT facilities typically offer a resolution of a few microns per voxel, resulting in a field of view of approximately 5 mm3 for a 2,0482 charge-coupled device. At this scale, the resolution is normally sufficient to resolve pore-space connectivity and calculate transport properties directly. For samples exhibiting heterogeneity above the field of view of such a single high-resolution tomogram with resolved pore space, a second low-resolution tomogram can provide a larger-scale porosity map. This low-resolution X-ray-CT image provides the correlation structure of porosity at an intermediate scale, for which high-resolution permeability calculations can be carried out, forming the basis for upscaling methods dealing with correlated heterogeneity. In this study, we characterize spatial heterogeneity by use of overlapping registered X-ray-CT images derived at different resolutions spanning orders of magnitude in length scales. A 38-mm-diameter carbonate core is studied in detail and imaged at low resolution—and at high resolution by taking four 5-mm-diameter subsets, one of which is imaged by use of full-length helical scanning. Fine-scale permeability transforms are derived by use of direct porosity/permeability relationships, random sampling of the porosity/permeability scatter plot as a function of porosity, and structural correlations combined with stochastic simulation. A range of these methods is applied at the coarse scale. We compare various upscaling methods, including renormalization theory, with direct solutions by use of a Laplace solver and report error bounds. Finally, we compare with experimental measurements of permeability at both the small-plug and the full-plug scale. We find that both numerically and experimentally for the carbonate sample considered, which displays nonconnecting vugs and intrafossil pores, permeability increases with scale. Although numerical and experimental results agree at the larger scale, the digital core-analysis results underestimate experimentally measured permeability at the smaller scale. Upscaling techniques that use basic averaging techniques fail to provide truthful vertical permeability at the fine scale because of large permeability contrasts. At this scale, the most accurate upscaling technique uses Darcy's law. At the coarse scale, an accurate permeability estimate with error bounds is feasible if spatial correlations are considered. All upscaling techniques work satisfactorily at this scale. A key part of the study is the establishment of porosity transforms between high-resolution and low-resolution images to arrive at a calibrated porosity map to constrain permeability estimates for the whole core.

scholarly journals Research of Temperature Conditions of Organic Sediments Formation in the Productive Formation at Paraffinic Oil Well Production

2021 ◽  
Vol 21 (2) ◽  
pp. 84-93
Author(s):  
Mikhail S. Sandyga ◽  
◽  
Ivan A. Struchkov ◽  
Mikhail K. Rogachev ◽  
◽  
...  
Keyword(s):  
Free Volume ◽  
Pore Space ◽  
Experimental Studies ◽  
Saturation Temperature ◽  
Reservoir Rock ◽  
Core Material ◽  
Reservoir Rocks ◽  
Temperature Conditions ◽  
Before And After ◽  
Paraffinic Oil

The paper presents the studies results of the temperature conditions for the formation of organic (asphalt-resin-paraffinic) deposits in the productive formation during the downhole production of paraffinic oil, including the results of experimental studies to assess the temperature of oil saturation with paraffin in the pore space of reservoir rocks. The studies were carried out in order to substantiate and develop a technology for preventing such deposits in the "reservoir - well" system. The results of filtration and rheological studies showed that for the same oil, the wax saturation temperature in the pore space of the reservoir rock could exceed the value of this parameter in the free volume. It was found that for the investigated solutions (models of highly paraffinic oils), the phase transition of paraffin from liquid to solid state, the formation of wax crystals in the pore space occured at a temperature 3-4° C higher than in the free volume. The results of tomographic studies of the core material, performed before and after filtration of a paraffin-containing solution through it with a decrease in temperature, showed that the open porosity of rock samples decreased on average four times due to the clogging of their pore space with paraffin. Based on the results of the filtration experiment and computed tomography, a digital core model was created, which allowed modeling the fluid flow in the pore space of the rock before and after the formation of paraffin deposits in it. The calculations results of the changes dynamics in the thermal field around the injection well confirmed the probability of cooling the bottomhole zone of the well to a temperature equal to the temperature of the onset of wax crystallization, as well as the probability of the cold water front advancing to neighboring production wells, which could cause a significant decrease in the productivity due to the formation of paraffin deposits in pore space of reservoir rocks. The research results are recommended to be taken into account when developing oil fields in conditions of possible formation of organic (asphalt-resin-paraffinic) deposits in the productive formation. This will make it possible to more reliably predict and effectively prevent its formation in the "reservoir - well" system.

scholarly journals EVALUATION OF PORE SYSTEM PROPERTIES OF COQUINAS FROM MORRO DO CHAVES FORMATION BY MEANS OF X-RAY MICROTOMOGRAPHY

2018 ◽  
Vol 36 (4) ◽  
pp. 1 ◽  
Author(s):  
João Pedro Tauscheck Zielinski ◽  
Alexandre Campane Vidal ◽  
Guilherme Furlan Chinelatto ◽  
Leandro Coser ◽  
Celso Peres Fernandes
Keyword(s):  
Pore Space ◽  
Total Porosity ◽  
Reservoir Rock ◽  
Absolute Permeability ◽  
Pore System ◽  
Pore Throat ◽  
X Ray ◽  
Petrophysical Parameters ◽  
Potential Reservoir ◽  
Rock Characterization

ABSTRACT. The recent increase in the use of X-ray microtomography (μ-CT) for reservoir rock characterization can be explained by numerous factors, such as its non-destructive nature, higher spatial resolution and 3D pore space visualization, which were explored in this work to evaluate the pore system of coquinas, a potential reservoir rock mainly composed of shells and their fragments. However, most of the recent studies have not considered an association between petrophysical parameters extracted via μ -CT and coquina facies. For this reason, this work had the goal to characterize the pore types, quantify total porosity, obtain the porosity profile, analyze the pore and pore-throat size distribution, as well as to extract additional petrophysical parameters of different taphofacies from Morro do Chaves Formation coquinas, Sergipe-Alagoas basin. The results haven shown that taphofacies from shallow sub-environment under normal conditions (group T2) and deeper sub-environment under storm influence (group T5) are better in terms of reservoir quality. Nevertheless, rocks from storm influence, deeper sub-environments are more likely to represent a good reservoir, since its pore system is predominantly dominated by moldic pores, which are originated during eogenetic phase, while rocks from shallow normal conditions have pores dominantly generated during telogenesis. Additionally, μ-CT derived data such as coordination number and pore and pore-throat sizes could also be used to explain differences in absolute permeability in the studied rocks. Nevertheless, our data suggests that coquinas have a multiscale pore system and finer imaging scales are indispensable for more accurate petrophysical characterization.  Keywords: Coquinas, μ-CT, petrophysics. RESUMO. A crescente utilização da microtomografia de raios-X (μ-CT) visando a caracterização das rochas reservatório pode ser explicada por diversos fatores, como sua natureza não-destrutiva, alta resolução espacial e visualização 3D do espaço poroso, que são propriedades exploradas nesse trabalho para avaliar o sistema poroso de coquinas, uma potencial rocha reservatório composta principalmente por conchas e seus respectivos fragmentos. Entretanto, a maioria dos estudos recentes não tem associado os parâmetros petrofísicos com as fácies de coquinas. Por essa razão, esse trabalho buscou realizar a caracterização dos tipos de poros, quantificar a porosidade total, obter o perfil de porosidade, analisar a distribuição do tamanho de poros e gargantas, assim como extrair parâmetros adicionais de diferentes tafofácies das coquinas da Fm. Morro do Chaves, Bacia de Sergipe-Alagoas. Os resultados mostraram que as tafofácies dos subambientes rasos sob condições normais de deposição (grupo T2) e dos subambientes profundos sob influência de tempestades (grupo T5) são melhores em termos de qualidade de reservatório. No entanto, as rochas de subambientes profundos sob influência de tempestades são mais prováveis de representarem bons reservatórios, pois seu sistema poroso é predominantemente dominado por poros móldicos, que são originados durante a fase eogenética, enquanto que as rochas depositadas no subambiente raso em condições normais possuem poros gerados durante a telogênese. Adicionalmente, dados derivados da μ-CT, como número de coordenação e tamanho de poros e gargantas, também poderiam ser usados para explicar as diferenças em permeabilidade absoluta nas rochas estudadas. Entretanto, nossos dados sugerem que as coquinas possuem um sistema poroso multiescalar e o imageamento em escalas mais finas para uma caracterização petrofísica mais acurada é indispensável.Palavras-chave: Coquinas, μ-CT, petrofísica

scholarly journals Evaluation of carbonate-clay cement impact on the permeability factor of reservoir rocks by geophysical data

2018 ◽  
pp. 48-56
Author(s):  
T. V. Potiatynnyk
Keyword(s):  
Hydrogen Content ◽  
Pore Space ◽  
Geophysical Data ◽  
Reservoir Rock ◽  
Core Material ◽  
Carbonate Content ◽  
Gas Field ◽  
Permeability Factor ◽  
Natural Gamma ◽  
G Value

Control over the process of reservoir flooding provides an opportunity to conduct efficient and rational operation of hydrocarbon deposits. Detailed monitoring of the flooding process requires the creation of geologicalfiltration models. The basis of the reservoir filtration model is the permeability factor; its reliability depends on various factors. It was proved that the reliability of permeability factor determination of Hidnovytske field is significantly affected by carbonate content. The research to determine connection of the natural gamma field intensity with the radiation capture of neutrons intensity on the basis of geological and geophysical borehole survey of the Hidnovitske gas field was performed. The model of reservoir rock neutron properties reflects the hydrogen content in the pore space and the characteristic of the mineral composition of the reservoir rock cement. This characteristic makes it possible to use neutron gamma logging to evaluate the carbonate content impact in determining the permeability factor. To evaluate the carbonate content, it was suggested to use relative parameter G, indicating the part of the rockdispersed fraction in the unit of hydrogen content. According to the results of laboratory measurements on core material and geophysical data of radioactive logging, the dependence of parameter G value on carbonate content was developed. The obtained dependence will allow to determine the proportion of carbonates in clay cement by parameter G value and correct the equation to determine the permeability factor. 

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