With the recent increase in natural gas production, the demand for college educated petroleum engineers has increased. A greater number of high school graduates are now applying to petroleum engineering degree programs, however, the admission requirements to petroleum engineering schools are becoming increasingly stricter. Secondary educators have a greater challenge to better prepare students to compete for these positions and there is a need to introduce petrophysical concepts to students in the most effective manner. One petrophysical concept is porosity of rock. In this report, background information on rock formation and porosity of rocks is provided along with a brief summary on how 3D printers operate. But primarily, a lesson plan is presented to teach rock porosity in a novel way using 3D printed enlargements of porous rock from x-ray microtomography images of packed sand. The hypothesis was that students will gain greater understanding of petrophysical properties when using 3D prints of rocks. The porosity lesson with a lab using the 3D printed rocks was taught to a treatment group of 20 upcoming 6th graders. A porosity lesson without the use of 3D printed rocks was didactically taught to a control group of 14 additional 6th graders. Because of time limitations, not all of the students from the treatment group were able to experience all elements of the lab. However, every student in the control group received instruction and practice on how to calculate porosity of rock. The treatment group showed greater gain in learning the abstract concept about porosity that rocks of similar structure will have equivalent porosity regardless of grain size. However, the control group indicated greater gain learning the fundamental concepts of the definition of porosity, how to calculate porosity, and at being able to transfer their knowledge of percent porosity to a general problem about percentages. Despite the limited sample size and other sources of error, using 3D printed enlargements of rock was found to enhance students’ abilities to visualize abstract petrophysical properties. However, benefits from didactic instruction of fundamental concepts of petrophysical properties were found as well. / text

Understanding the controls on fluid migration in reservoir rocks is becoming evermore important within the petroleum industry as significant hydrocarbon discoveries become less frequent and more emphasis is placed on enhanced oil recovery methods. To fully understand the factors controlling fluid migration in the subsurface, pore scale information is necessary. In this study, synchrotron-based X-ray computed microtomography (CMT) is being utilized to extract physically realistic images of carbonate rock cores for the evaluation of porosity and mineralogy in the Mississippian Midale beds of the Weyburn Oilfield in southeastern Saskatchewan. Non-destructive in-situ imaging by CMT is unique as it provides a detailed and novel approach for the description of pore space geometry, while preserving connectivity and spatial variation of pore-body and pore-throat sizes. Here, three-dimensional micron to sub-micron (0.3ìm-100ìm) resolution of CMT is coupled with, and compared against, conventional laboratory-based methods (liquid and gas permeametry, mercury injection porosimetry, electrical resistivity, backscattered electron (BSE) from electron probe micro-analysis (EPMA) and transmitted light microscopy). Petrophysical and mineralogical information obtained from both CMT and conventional methods will have direct implications for understanding the petrophysical mechanisms that control fluid movement in the subsurface of the Weyburn Oilfield.<p>At Weyburn, CO2 gas is being injected into producing horizons to enhance oil recovery and permanently sequester CO2 gas. Fundamental questions exist regarding: (1) The significance of pore geometry and connectivity to the movement of CO2 and other fluids in the subsurface, (2) the nature of the interactions between CO¬2 and pore lining minerals and their impact on petrophysical properties, and (3) the distribution and mineralogy of finely disseminated silicate and carbonate minerals adjacent to pore spaces as interaction among these phases and CO2 may result in permanent sequestration of CO2. <p>The two producing horizons within the Weyburn Reservoir, the Midale Marly and Midale Vuggy units, have variable porosities and permeabilities. Porosity in the Marly unit ranges from 16% to 38% while permeability ranges from 1mD to greater than 150 mD across the field. For the Vuggy unit, porosity ranges from 8% to 21% with permeability ranging from 0.3mD to 500mD. Using CMT, pore space is critically examined to highlight the controlling factors on permeability. Digital processing of CMT data indicates that pore space in the Marly unit is dominated by intercrystalline pores having diameters of approximately 4 ìm. From here, it is noted that the pore-throat radii are approximately ½ the radii of the pore-bodies, having profound implications to current oil recovery methods. Tortuosity values from CMT are also observed to have similar values in three orthogonal directions indicating an isotropic pore space distribution within the Marly unit. Alternatively, the Vuggy unit is found to possess greater pore-body and pore-throat sizes that are heterogeneous in distribution. Based on this, permeability in the Vuggy unit is strongly dependant on pore-length scales that vary drastically between localities.

Understanding the controls on fluid migration in reservoir rocks is becoming evermore important within the petroleum industry as significant hydrocarbon discoveries become less frequent and more emphasis is placed on enhanced oil recovery methods. To fully understand the factors controlling fluid migration in the subsurface, pore scale information is necessary. In this study, synchrotron-based X-ray computed microtomography (CMT) is being utilized to extract physically realistic images of carbonate rock cores for the evaluation of porosity and mineralogy in the Mississippian Midale beds of the Weyburn Oilfield in southeastern Saskatchewan. Non-destructive in-situ imaging by CMT is unique as it provides a detailed and novel approach for the description of pore space geometry, while preserving connectivity and spatial variation of pore-body and pore-throat sizes. Here, three-dimensional micron to sub-micron (0.3ìm-100ìm) resolution of CMT is coupled with, and compared against, conventional laboratory-based methods (liquid and gas permeametry, mercury injection porosimetry, electrical resistivity, backscattered electron (BSE) from electron probe micro-analysis (EPMA) and transmitted light microscopy). Petrophysical and mineralogical information obtained from both CMT and conventional methods will have direct implications for understanding the petrophysical mechanisms that control fluid movement in the subsurface of the Weyburn Oilfield.<p>At Weyburn, CO2 gas is being injected into producing horizons to enhance oil recovery and permanently sequester CO2 gas. Fundamental questions exist regarding: (1) The significance of pore geometry and connectivity to the movement of CO2 and other fluids in the subsurface, (2) the nature of the interactions between CO¬2 and pore lining minerals and their impact on petrophysical properties, and (3) the distribution and mineralogy of finely disseminated silicate and carbonate minerals adjacent to pore spaces as interaction among these phases and CO2 may result in permanent sequestration of CO2. <p>The two producing horizons within the Weyburn Reservoir, the Midale Marly and Midale Vuggy units, have variable porosities and permeabilities. Porosity in the Marly unit ranges from 16% to 38% while permeability ranges from 1mD to greater than 150 mD across the field. For the Vuggy unit, porosity ranges from 8% to 21% with permeability ranging from 0.3mD to 500mD. Using CMT, pore space is critically examined to highlight the controlling factors on permeability. Digital processing of CMT data indicates that pore space in the Marly unit is dominated by intercrystalline pores having diameters of approximately 4 ìm. From here, it is noted that the pore-throat radii are approximately ½ the radii of the pore-bodies, having profound implications to current oil recovery methods. Tortuosity values from CMT are also observed to have similar values in three orthogonal directions indicating an isotropic pore space distribution within the Marly unit. Alternatively, the Vuggy unit is found to possess greater pore-body and pore-throat sizes that are heterogeneous in distribution. Based on this, permeability in the Vuggy unit is strongly dependant on pore-length scales that vary drastically between localities.

Submitted by Emanuel Varela Cardoso (emanuel.varela@ufcg.edu.br) on 2018-08-30T23:05:10Z No. of bitstreams: 1 CARLOS HENRICKSON BARBALHO DE MOURA – DISSERTAÇÃO (PPGEPM) 2018.pdf: 10493787 bytes, checksum: 063013097342f1433f86bc8ac8434722 (MD5) / Made available in DSpace on 2018-08-30T23:05:10Z (GMT). No. of bitstreams: 1 CARLOS HENRICKSON BARBALHO DE MOURA – DISSERTAÇÃO (PPGEPM) 2018.pdf: 10493787 bytes, checksum: 063013097342f1433f86bc8ac8434722 (MD5) Previous issue date: 2018-03-28 / Capes / A petrofísica computacional é uma técnica que vem sendo utilizada cada vez mais na indústria do petróleo para caracterizar reservatórios e simular computacionalmente o seu comportamento físico. Através dessa técnica é possível caracterizar um elevado número de amostras, sob diferentes condições ambientais, em um tempo relativamente curto. Este trabalho propõe um modelo de estimativa de permeabilidade que utiliza parâmetros petrofísicos retirados de imagens de microtomografia de raios x (µCT) e os compara com parâmetros petrofísicos medidos em laboratório. Foi analisado um conjunto de 19 amostras com características deposicionais, diagenéticas e texturais diferentes entre si, pertencentes às bacias do Araripe, Potiguar e Sergipe-Alagoas. Delas, 14 são de calcário, 2 de tufa calcária, 2 de caliche e 1 de dolomito. Em laboratório foi utilizado um permoporosímetro a gás para medir os parâmetros porosidade e permeabilidade. As amostras de µCT foram adquiridas com resolução em torno de 2,0 µm. O conjunto de imagens criado foi tratado no software Avizo Fire e foram extraídos os parâmetros porosidade, permeabilidade, conectividade e diâmetro equivalente de poros. Um modelo estatístico foi estabelecido para predição da permeabilidade a partir dos parâmetros do espaço poroso extraídos das imagens de µCT. Os resultados indicam que a conectividade dos microporos, inferida a partir do cálculo do Número de Euler em imagens 3D, é o parâmetro que exerce maior influência na estimativa da permeabilidade, seguida pela porosidade dos macroporos e pela conectividade dos macroporos. O modelo preditivo proposto apresentou um coeficiente de determinação de 0,994, mostrando-se bastante confiável para o grupo de amostras investigado. / Computational petrophysics is a technique that has been increasingly used in the petroleum industry to characterize reservoirs and to simulate computationally its physical behavior. Through this technique it is possible to characterize a big number of samples, under different environmental conditions, in a relatively short time. This work proposes a model of permeability estimation that uses petrophysical parameters taken from x - ray microtomography images (µCT) and compare them with petrophysical parameters measured in the laboratory. It was analyzed a set of 19 samples with different depositional, diagenetic and textural characteristics, belonging to the Araripe, Potiguar and Sergipe - Alagoas basins. Of these, 14 are limestones, 2 of tufa limestone, 2 of caliche and 1 of dolomite. In the laboratory a gas permoporosimeter was used to measure the porosity and permeability parameters. µCT samples were obtained with a resolution of about 2.0 μm. The set of images created was treated in Avizo Fire software and the porosity, permeability, connectivity and pore diameter parameters were extracted. A statistical model was established to predict permeability from pore space parameters extracted from µCT images. The results indicate that the connectivity of micropores, inferred from the calculation of the Euler Number in 3D images, is the parameter that exerts the greatest influence in the estimation of permeability, followed by the porosity of the macropores and the connectivity of the macropores. The proposed predictive model presented a coefficient of determination of 0.994, being very reliable for the group of samples investigated.

>Magister Scientiae - MSc / The evaluation of petroleum reservoirs has shifted from single approach to an integrated approach. The integration, analysis and understanding of all available data from the well bore and creating property models is an exceptional way to characterize a reservoir. Formulating, implementing, and demonstrating the applicability of the joint inversion of seismic and well-bore related observations, and the use of information about the relationship between porosity and permeability as the key parameters for identifying the rock types and reservoir characterization is a vital approach in this study. Correlating well and seismic data, potential reservoirs can be delineated and important horizons (markers) can be pointed out to better characterize the reservoir. This thesis aims to evaluate the potential petroleum reservoirs of the Wells K-A1, K-A2, K-A3 and K-H1 of the Shungu Shungu field in the Orange Basin through the integration and comparison of results from core analysis, wireline logs and seismic and attempt to produce a good reservoir model and by additionally utilizing Petrophysics and seismic and trying to better understand why the area has dry wells. Different rock types that comprise reservoir and non reservoirs are identified in the study and five Facie types are distinguished. Tight, fine grained sandstones with low porosity values ranging from 3% - 6% where dominant in the targeted sandstone layers. Porosity values ranging from 11% - 18% where identified in the massive sandstone lithologies which where hosted by Well’s K-A2 and K-A3. Low permeability values reaching 0.1mD exist throughout the study area. Areas with high porosity also host high water saturation values ranging from 70 – 84%. An improvement in the porosity values at deeper zones (3700m -3725m) and is apparent. Poroperm plots exhibit quartz cemented sandstones and density with neutron plot suggest that the sandstones in the area contain quarts and dolomite mineralization.Well K-A3, consist of a cluster by quartzitic sandstone, meaning there is a large amount of sandstone present. There are apparent high porosity values around the sandstone. What is apparent from this plot is that there are many clusters that are scattered outside the chart. This could suggest some gas expulsions within this Well. Sandstones within the 14B2t1 to 14At1 interval are less developed in the vicinity covered by well K-A2 than at the K-A1 well location. The main targeted sandstones belong to the lower cretaceous and lie just below 13At1. The four wells drilled in this area are dry wells. The areas/blocks surrounding this area have shown to possess encouraging gas shows and a comparative study could reveal better answers. At deeper zones of the well at an interval of 5350m -5750m, there are more developed sandstones with good porosity values. The volume of shale is low and so is the water saturation. The main target sandstones in the study area are the Lower Cretaceous sandstones which are at an interval 13At1. These sandstones are not well developed but from the property model of the target surface it can be seen that the porosity values are much more improved than the average values applied on all the zones on the 3D grid.

All the oil and gas wells producing in the Arikaree Creek Field, Colorado targeted the Spergen Formation along similar structures within a wrench fault system; however, the wells have vastly different production values. This thesis develops a predictive model for high production in the field while also accounting for a failed waterflood event that was initiated in 2016. Petrophysical analysis of thirteen wells show that high producing wells share common characteristics of pay zone location, lithology, porosity and permeability with one another and that the Spergen Formation is not homogenous. Highly productive wells have pay zones in the lower part of the formation in sections that are dolomitized, and have anonymously high water saturation. This is likely related to the paragenesis of the formation that dolomitized the lower parts of the formation, increasing porosity and permeability, but leaving the pay zones with the high water saturation values. This heterogeneity likely accounts for the failed waterflood. Results show that the important petrophysical components for highly productive wells are the location of the payzone within the reservoir, porosity, permeability and water saturation. Additionally, homogeneity is crucial for successful waterflooding, which was not present.

Petrophysical properties are fundamental to understanding fluid flow processes in hydrocarbon reservoirs. Special Core Analysis (SCAL) routinely used in industry are time-consuming, expensive, and often destructive. Alternatively, easily available thin section data is lacking the representation of pore space in 3D, which is a requisite for generating pore network models (PNM) and computing petrophysical properties. In this study, these challenges were addressed using a numerical SCAL workflow that employs pore volume reconstruction from thin section images obtained from confocal laser scanning microscopy (CLSM). A key objective is to investigate methods capable of 2D to 3D reconstruction, to obtain PNM used for the estimation of transport properties. Representative thin sections from a well-known Middle-Eastern carbonate formation were used to obtain CLSM images. The thin-sections were specially prepared by spiking the resin with UV dye, enabling high-resolution imaging. The grayscale images obtained from CLSM were preprocessed and segmented into binary images. Generative Adversarial Networks (GAN) and Two-Point Statistics (TPS) were applied, and PNM were extracted from these binary datasets. Porosity, Permeability, and Mercury Injection Porosimetry (MIP) on the corresponding core plugs were conducted and an assessment of the properties computed from the PNM obtained from the reconstructed 3D pore volume is presented. Moreover, the results from the artificial pore networks were corroborated using 3D confocal images of etched pore casts (PCE). The results showed that based on visual inspection only, GAN outperformed TPS in mimicking the 3D distribution of pore scale heterogeneity, additionally, GAN and PCE outperformed the results of MIP obtained by TPS on the Skeletal-Oolitic facies, without providing a major improvement on more heterogeneous samples. All methods captured successfully the porosity while absolute permeability was not captured. Formation resistivity factor and thermal conductivity showcased their strong correlation with porosity. The study thus provides valuable insights into the application of 2D to 3D reconstruction to obtain pore network models of heterogeneous carbonate rocks for petrophysical characterization for quick decision. The study addresses the following important questions: 1) how legacy thin sections can be leveraged to petrophysically characterize reservoir rocks 2) how reliable are 2D to 3D reconstruction methods when predicting petrophysical properties of carbonates.

Undulating well trajectories are often drilled to improve length exposure to rock formations, target desirable hydrocarbon-saturated zones, and enhance resolution of borehole measurements. Despite these merits, undulating wells can introduce adverse conditions to the interpretation of borehole measurements which are seldom observed in vertical wells penetrating horizontal layers. Common examples are polarization horns observed across formation bed boundaries in borehole resistivity measurements acquired in highly-deviated wells. Consequently, conventional interpretation practices developed for vertical wells can yield inaccurate results in HA/HZ wells. A reliable approach to account for well trajectory and bed-boundary effects in the petrophysical interpretation of well logs is the application of forward and inverse modeling techniques because of their explicit use of measurement response functions. The main objective of this dissertation is to develop inversion-based petrophysical interpretation methods that quantitatively integrate logging-while-drilling (LWD) multi-sector nuclear (i.e., density, neutron porosity, photoelectric factor, natural gamma ray) and multi-array propagation resistivity measurements. Under the assumption of a multi-layer formation model, the inversion approach estimates formation properties specific to a given measurement domain by numerically reproducing the available measurements. Subsequently, compositional multi-mineral analysis of inverted layer-by-layer properties is implemented for volumetric estimation of rock and fluid constituents. The most important prerequisite for efficient petrophysical inversion is fast and accurate forward models that incorporate specific measurement response functions for numerical simulation of LWD measurements. In the nuclear measurement domain, first-order perturbation theory and flux sensitivity functions (FSFs) are reliable and accurate for rapid numerical simulation. Albeit efficient, these first-order approximations can be inaccurate when modeling neutron porosity logs, especially in the presence of borehole environmental effects (tool standoff or/and invasion) and across highly contrasting beds and complex formation geometries. Accordingly, a secondary thrust of this dissertation is the introduction of two new methods for improving the accuracy of rapid numerical simulation of LWD neutron porosity measurements. The two methods include: (1) a neutron-density petrophysical parameterization approach for describing formation macroscopic cross section, and (2) a one-group neutron diffusion flux-difference method for estimating perturbed spatial neutron porosity fluxes. Both methods are validated with full Monte Carlo (MC) calculations of spatial neutron detector FSFs and subsequent simulations of neutron porosity logs in the presence of LWD azimuthal standoff, invasion, and highly dipping beds. Analysis of field and synthetic verification examples with the combined resistivity-nuclear inversion method confirms that inversion-based estimation of hydrocarbon pore volume in HA/HZ wells is more accurate than conventional well-log analysis. Estimated hydrocarbon pore volume from conventional analysis can give rise to errors as high as 15% in undulating HA/HZ intervals. / text

The X-Ray imaging technology opened a new branch of science in which the internal porous structure can be captured and the reconstructed volume can be used for fluid flow simulations and structural measurements. However, there is still the question of how the internal structure of the pore space impacts in the observed simulations. A way to characterize this internal structure is by simplifying it into well-defined elements and the interaction between them, describing it as a network. The interaction between elements are the edges of the network and elements are the nodes. This opens the possibility of applying complex network theory on the characterization of porous media which has proven to give powerful insights into how the structure of porous materials influences on the dynamics of the permeating fluid. The problem with this description is in definition of the basic elements that will compose the network, since there isnt a consensus on this definition. The purpose of this work is to provide a method to analyze &mu;CT data through networks in which the separation of the space is done in a semi-continuous method. The recovering of the pores local geometry is captured through a network analysis method of centrality, instead of a geometrical definition. This way the intrinsic morphology of the samples is what governs the pore-space separation into different entities. The method developed is based on the network extraction method Max Spheres Algorithm (MSA). The volumetric data is recovered through a network composed by sphere cells. The output of this process are two distinct networks: the complete volume network and a network which represents the variation of the channels diameter. These networks give unbiased real information on pore connectivity and can provide important data to better understand the morphology and topology of the samples. This method was successfully applied to samples of Berea sandstone, Estaillades carbonate, and to characterize the morphology of wormholes. Wormhole is the denomination of the channel formed after the application of an acid treatment as a stimulation procedure of an oil reservoir, a method of EOR (Enhanced oil recovery). This treatment consists of a reactive fluid flow injected in the inner rock of the reservoir, which creates a preferential path (wormhole) that optimizes the extraction of the hydrocarbon fluids. / A microtomografia de raios-X permitiu a evolução de uma nova área da ciência aplicada a meios porosos: a Rocha Digital. Através desta técnica, todo o espaço poroso é recuperado, e é possível entender a dinâmica do fluido que o permeia através de simulações computacionais. No entanto, ainda há a questão de como a estrutura do meio influencia nos resultados observados. Entender questões como connectividade e clusterização de regiões podem dar informações valiosas sobre como a origem do meio poroso influencia na dinâmica do fluido que o permeia. Esta avaliação do meio é possível através da simplificação do mesmo em uma rede de conexão de elementos básicos e as interações entre estes. O problema com a descrição do meio poroso em uma rede de conexão é que não existe um consenso na definição destes elementos básicos. O propósito deste trabalho foi encontrar uma maneira de descrever o meio que fosse aplicável a qualquer litologia, e que se aproximasse ao máximo dos dados extraídos pela micro tomografia para a análise das topologias de diferentes rochas através de teoria de redes complexas.Para isso, utilizamos o algoritmo robusto de extração de redes de poros, esferas máximas, como base para dividir o espaço-poroso em células esféricas. Desta forma, todo o volume do espaço poroso observado através da micro tomografia é recuperado e descrito em uma rede de conexão. O resultado final do método aplicado é uma rede que descreve o meio completo e uma rede que descreve o eixo medial das interconexões entre poros. A geometria local dos poros é recuperada através de um critério de centralidade de rede, assim a separação é governada pela morfologia intrínseca das amostras, ao invés de fatores geométricos.Desta forma podemos analisar o efeito da tortuosidade real do meio, assim como a interconexão entre poros, com relação a permeabilidade do meio.O método se mostrou eficaz na análise de rochas com diferentes litologias: arenito (Berea) e carbonato (Estaillades). O método também foi aplicado na avaliação da estrutura de canais formados pelo processo de acidificação de rochas (wormholes).

Dans cette thèse, on s'intéresse à l’automatisation de l’identification et de la caractérisation de strates géologiques à l’aide des diagraphies de puits. Au sein d’un puits, on détermine les strates géologiques grâce à la segmentation des diagraphies assimilables à des séries temporelles multivariées. L’identification des strates de différents puits d’un même champ pétrolier nécessite des méthodes de corrélation de séries temporelles. On propose une nouvelle méthode globale de corrélation de puits utilisant les méthodes d’alignement multiple de séquences issues de la bio-informatique. La détermination de la composition minéralogique et de la proportion des fluides au sein d’une formation géologique se traduit en un problème inverse mal posé. Les méthodes classiques actuelles sont basées sur des choix d’experts consistant à sélectionner une combinaison de minéraux pour une strate donnée. En raison d’un modèle à la vraisemblance non calculable, une approche bayésienne approximée (ABC) aidée d’un algorithme de classification basé sur la densité permet de caractériser la composition minéralogique de la couche géologique. La classification est une étape nécessaire afin de s’affranchir du problème d’identifiabilité des minéraux. Enfin, le déroulement de ces méthodes est testé sur une étude de cas. / In this thesis, we investigate the automation of the identification and the characterization of geological strata using well logs. For a single well, geological strata are determined thanks to the segmentation of the logs comparable to multivariate time series. The identification of strata on different wells from the same field requires correlation methods for time series. We propose a new global method of wells correlation using multiple sequence alignment algorithms from bioinformatics. The determination of the mineralogical composition and the percentage of fluids inside a geological stratum results in an ill-posed inverse problem. Current methods are based on experts’ choices: the selection of a subset of mineral for a given stratum. Because of a model with a non-computable likelihood, an approximate Bayesian method (ABC) assisted with a density-based clustering algorithm can characterize the mineral composition of the geological layer. The classification step is necessary to deal with the identifiability issue of the minerals. At last, the workflow is tested on a study case.