Dissertations / Theses: 'Petrophysical analysis'

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Kamgang, Thierry T. "Petro physical evaluation of four wells within Cretaceous gas-bearing sandstone reservoirs, In block 4 and 5 orange basin, South Africa." University of the Western Cape, 2013. http://hdl.handle.net/11394/4259.

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Masters of Science
Petrophysical evaluation of four wells within Cretaceous gas-bearing sandstone reservoirs in blocks 4 and 5 Orange Basin, South Africa. Thierry Kamgang The present research work evaluates the petrophysical characteristics of the Cretaceous gasbearing sandstone units within Blocks 4 and 5 offshore South Africa. Data used to carry out this study include: wireline logs (LAS format), base maps, well completion reports, petrography reports, conventional core analysis report and tabulated interpretative age reports from four wells (O-A1, A-N1, P-A1 and P-F1). The zones of interest range between 1410.0m-4100.3m depending on the position of the wells. The research work is carried out in two phases: The first phase corresponds to the interpretation of reservoir lithologies based on wireline logs. This consists of evaluating the type of rocks (clean or tight sandstones) forming the reservoir intervals and their distribution in order to quantify gross zones, by relating the behavior of wireline logs signature based on horizontal routine. Extensively, a vertical routine is used to estimate their distribution by correlating the gamma-ray logs of the corresponding wells, but also to identify their depositional environments (shallow to deep marine).Sedlog software is used to digitize the results. The second phase is conducted with the help of Interactive Petrophysics (version 4) software, and results to the evaluation of eight petrophysical parameters range as follow: effective porosity (4.3% - 25.4%), bulk volume of water (2.7% – 31.8%), irreducible water saturation (0.2%-8.8%), hydrocarbon saturation (9.9% - 43.9%), predicted permeability (0.09mD – 1.60mD), volume of shale (8.4% - 33.6%), porosity (5.5% - 26.2%) and water saturation (56.1% - ii 90.1%). Three predefined petrophysical properties (volume of shale, porosity and water saturation)are used for reservoir characterization. The volume of shale is estimated in all the wells using corrected Steiber method. The porosity is determined from the density logs using the appropriate equations in wells O-A1 and P-A1, while sonic model is applied in well A-N1 and neutron-density relationship in well P-F1. Formation water resistivity (Rw) is determined through the following equation: Rw = (Rmf × Rt) / Rxo, and water saturation is calculated based on Simandoux relation. Furthermore, a predicted permeability function is obtained from the crossplot of core porosity against core permeability, and it results match best with the core permeability of well O-A1. This equation is used to predict the permeability in the other wells. The results obtained reveal that average volumes of shale decrease from the west of the field towards the east; while average porosities and water saturations increase from the south-west through the east despite the decreasing average water saturation in well P-A1. A corroboration of reference physical properties selected for reservoir characterization, with predefined cut-off values result to no net pay zones identified within the reservoir intervals studied. Consequently, it is suggested that further exploration prospects should be done between well O-A1 and A-N1.

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Deakin, Mark J. W. "Integration of core and log data for petrophysical analysis of Brae conglomerates, North Sea." Thesis, Imperial College London, 1989. http://hdl.handle.net/10044/1/7475.

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Olajide, Oluseyi. "The petrophysical analysis and evaluation of hydrocarbon potential of sandstone units in the Bredasdorp Central Basin." Thesis, University of the Western Cape, 2005. http://etd.uwc.ac.za/index.php?module=etd&action=viewtitle&id=gen8Srv25Nme4_9559_1181561577.

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This research was aimed at employing the broad use of petrophysical analysis and reservoir modelling techniques to explore the petroleum resources in the sandstone units of deep marine play in the Bredasdorp Basin.

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Sbiga, Hassan M. "Prediction and measurement of special core analysis petrophysical parameters in the Nubian sandstone of the North Africa." Thesis, Heriot-Watt University, 2013. http://hdl.handle.net/10399/2677.

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One of the main objectives of this work was to investigate the applicability and accuracy of artificial neural networks for estimating special core analysis (SCAL) parameters from minimal core training data and wireline logs. The SCAL data was obtained from measurements on core plugs undertaken at the Libyan Petroleum Institute (L.P.I). Previous neural network studies have attempted to predict routine core analysis parameters, such as permeability, but not SCAL parameters such as true formation resistivity (Rt), resistivity index (RI), water saturation (Sw), saturation exponent (n) and Amott-Harvey Wettability Index (IA/H). Different combinations of wireline logs were used to train a variety of neural network predictors. Some of the predictors were trained using a large dataset from the entire cored interval of the training well. Other genetically focused neural network (GFNN) predictors were trained just from one short representative genetic unit (RGU) in the training well. The predictors were then tested in an adjacent well in the same oil field and also in another well in a different oil field. Significantly the performance of the GFNN predictors was as good (and in most cases better) than the predictors trained on the much larger dataset. This demonstrated the useful of the GFNN approach, which is very cost effective in terms of the minimal core that is required, and the reduced computer processing time. Moreover, this is the first time that these GFNN predictors have been used to predict SCAL parameters in the studied area, the Nubian Sandstone Formation in North Africa. These neural network predictors are particularly useful in this area due to the limited amount of SCAL data that is currently available. Quantitative statistical measures of heterogeneity were also examined on the reservoir samples, followed by a comparative analysis of hydraulic units (HUs) with a newer approach of global hydraulic elements (GHEs) to characterize the reservoir units in the studied area. The GHEs were then applied to select minimal representative core training data to train the genetically focused neural networks (GFNNs) to predict the SCAL parameters. The thesis also describes the factors affecting SCAL resistivity parameters. Laboratory measurements on the Nubian Sandstone reservoir rock samples showed changes in the formation resistivity factor (F) and cementation exponent (m) between ambient conditions and at overburden pressures. Changes were also observed in the saturation exponent (n) before and after wettability measurement. The experimental results also showed that there was a good relation between resistivity and the type of pore system which is consistent with study result from Swanson (1985) confirming earlier work.

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Kravets, Svetlana. "Stochastic modelling of the reservoir lithological and petrophysical attributes. A case study of the Middle East carbonate reservoir." Master's thesis, Faculdade de Ciências e Tecnologia, 2012. http://hdl.handle.net/10362/7834.

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Dissertação para obtenção do Grau de Mestre em Engenharia Geológica (Georrecursos)
Carbonate reservoirs represent the significant part of oil and gas production. They produce about 50% of hydrocarbons globally. In order to provide the rational exploitation of deposits in carbonate reservoirs it is necessary to ensure accurate prediction and effectively overcome the technical barriers that occur in a complex carbonate formations. The main rules for successful project are to develop and apply reservoir characteristics, to predict performance and productivity, effectively manage diagenesis to optimize production and maximize recovery through reservoir simulation technology. The great development of digital modelling technologies gives the opportunities to solve these problems. Generation of models of carbonate reservoir rocks by simulating the results of the geological processes involved is very complicated. Mainly because the rock may have undergone several phases of diagenetic processes that might have modified or even completely overprinted texture and fabrics of the original carbonate rock. In spite of this problem, a modelling technique, originally developed for sandstones, has successfully been extended for the 3D modeling of carbonate reservoir rocks. The input data to the modelling is obtained from the geophysical data and logging. In the present work, the virtual pore scale models of carbonates were produced by simulating the results of the geological processes. The implemented methodology was divided into two main steps. The first stage was a Lithoclasses Modelling. The 3D stochastic geological model of the lithology was produced by the Sequential Indicator Simulation (SIS) algorithm. The second stage was an attribute modelling. The main properties such as porosity and permeability were computed according to the lithoclasses via Direct Sequential Simulation (DSS) algorithm with local histograms. The comparison of the two data sets showed high convergence for the main calculated properties. In the final stage of the work the geobody analysis was conducted. This type of the connectivity analysis performed the geometry of geological facies, trends for property distribution and permeability barriers.

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DePriest, Keegan. "PETROPHYSICAL ANALYSIS OF WELLS IN THE ARIKAREE CREEK FIELD, COLORADO TO DEVELOP A PREDICTIVE MODEL FOR HIGH PRODUCTION." OpenSIUC, 2019. https://opensiuc.lib.siu.edu/theses/2609.

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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.

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Mosavel, Haajierah. "Petrophysical characterization of sandstone reservoirs through boreholes E-S3, E-S5 and F-AH4 using multivariate statistical techniques and seismic facies in the Central Bredasdorp Basin." Thesis, University of the Western Cape, 2014. http://hdl.handle.net/11394/3984.

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>Magister Scientiae - MSc
The thesis aims to determine the depositional environments, rock types and petrophysical characteristics of the reservoirs in Wells E-S3, E-S5 and F-AH4 of Area X in the Bredasdorp Basin, offshore South Africa. The three wells were studied using methods including core description, petrophysical analysis, seismic facies and multivariate statistics in order to evaluate their reservoir potential. The thesis includes digital wireline log signatures, 2D seismic data, well data and core analysis from selected depths. Based on core description, five lithofacies were identified as claystone (HM1), fine to coarse grained sandstone (HM2), very fine to medium grained sandstone (HM3), fine to medium grained sandstone (HM4) and conglomerate (HM5). Deltaic and shallow marine depositional environments were also interpreted from the core description based on the sedimentary structures and ichnofossils. The results obtained from the petrophysical analysis indicate that the sandstone reservoirs show a relatively fair to good porosity (range 13-20 %), water saturation (range 17-45 %) and a predicted permeability (range 4- 108 mD) for Wells E-S3, E-S5 andF-AH4. The seismic facies model of the study area shows five seismic facies described as parallel, variable amplitude variable continuity, semi-continuous high amplitude, divergent variable amplitude and chaotic seismic facies as well as a probable shallow marine, deltaic and submarine fan depositional system. Linking lithofacies to seismic facies maps helped to understand and predict the distribution and quality of reservoir packages in the studied wells

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De, Gasperi Patricia Martins Silva. "Estimativa de propriedades petrofisicas atraves da reconstrução 3D do meio poroso a partir da analise de imagens." [s.n.], 1999. http://repositorio.unicamp.br/jspui/handle/REPOSIP/264010.

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Orientadores: Euclides Jose Bonet, Marco Antonio Schreiner Moraes
Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica
Made available in DSpace on 2018-07-26T08:21:56Z (GMT). No. of bitstreams: 1 DeGasperi_PatriciaMartinsSilva_M.pdf: 13462853 bytes, checksum: cff9140cfbd41d9dc52865fb52425605 (MD5) Previous issue date: 1999
Resumo: Este trabalho tem como objetivos o estudo e a aplicação do processo de estimativa de propriedades petrofisicas a partir de informações obtidas em imagens petrográficas bidimensionais. O método assume a hipótese da homogeneidade estatística, e utiliza a simulação estocástica para a reconstrução do modelo tridimensional do meio poroso. A caracterização geométrica do meio simulado permite a elaboração de um modelo de rede para a simulação do fluxo e a estimativa da permeabilidade, fator de formação, pressão capilar por injeção de mercúrio e relação índice de resistividade versus saturação de água. Esta metodologia é aplicada a quatro sistemas porosos com diferentes níveis de heterogeneidade. Os resultados demonstram que estimativas confiáveis dependem da utilização de uma resolução apropriada de aquisição das imagens, que permita a identificação de poros e gargantas que efetivamente controlem as propriedades de fluxo do sistema. As curvas de pressão capilar simuladas sugerem a necessidade da composição de escalas. As propriedades elétricas são afetadas pela porosidade das amostras e sua confiabilidade é restrita a sistemas preferencialmente molháveis pela água
Abstract: The aim of this work is to investigate and apply a method for predicting petrophysical properties ftom bidimensional petrographic image data. Based on the assumption of statistical homogeneity, the method uses stochastic simulation to reconstruct the porous media tridimensional structure. The geometrical characterization of the simulated media allows the construction of a network model to simulate fluid flow and estimate permeability, formation factor, mercury capillary pressure curves and resistivity index as function of water saturation. This method is applied to four porous systems with different heterogeneity levels. The results demonstrate that good predictions depend on the appropriate image aquisition resolution, which identifies pores and throats that effectively control the flow properties of the system. The capillary pressure curves suggest the necessity of scale composition. The electrical properties are affected by samples porosity, with reliable estimates being restricted to water-wet systems
Mestrado
Mestre em Engenharia de Petróleo

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Schalkwyk, Hugh Je-Marco. "Assessment controls on reservoir performance and the affects of granulation seam mechanics in the Bredasdorp Basin, South Africa." Thesis, University of the Western Cape, 2006. http://etd.uwc.ac.za/index.php?module=etd&action=viewtitle&id=gen8Srv25Nme4_3459_1183461991.

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The Bredasdorp Basin is one of the largest hydrocarbon producing blocks within Southern Africa. The E-M field is situated approximate 50 km west from the FA platform and was brought into commission due to the potential hydrocarbons it may hold. If this field is brought up to full producing capability it will extend the lifespan of the refining station in Mosselbay, situated on the south coast of South Africa, by approximately 8 to 10 years. An unexpected pressure drop within the E-M field caused the suite not to perform optimally and thus further analysis was imminent to assess and alleviate the predicament. The first step within the project was to determine what might have cause the pressure drop and thus we had to go back to cores drilled by Soekor now known as Petroleum South Africa, in the early 1980&rsquo
s.

Analyses of the cores exposed a high presence of granulation seams. The granulation seams were mainly subjected within sand units within the cores. This was caused by rolling of sand grains over one another rearranging themselves due to pressure exerted through compaction and faulting, creating seal like fractures within the sand. These fractures caused these sand units to compartmentalize and prohibit flow from one on block to the next. With advance inquiry it was discovered that there was a shale unit situated within the reservoir dividing the reservoir into two main compartments. At this point it was determined to use Petrel which is windows based software for 3D visualization with a user interface based on the Windows Microsoft standards. This is easy as well as user friendly software thus the choice to go with it. The software uses shared earth modeling tool bringing about reservoir disciplines trough common data modelling. This is one of the best modelling applications in the available and it was for this reason that it was chosen to apply within the given aspects of the project A lack of data was available to model the granulation seams but with the data acquired during the core analyses it was possible to model the shale unit and factor in the influences of the granulation seams to asses the extent of compartmentalization. The core revealed a thick shale layer dividing the reservoir within two sections which was not previously noted. This shale layer act as a buffer/barrier restricting flow from the bottom to the top halve of the reservoir. This layer is thickest at the crest of the 10km²
domal closure and thins toward the confines of the E-M suite. Small incisions, visible within the 3 dimensional models could serve as a guide for possible re-entry points for future drilling. These incisions which were formed through Lowstand and Highstand systems tracts with the rise and fall of the sea level. The Bredasdorp Basin consists mainly of tilting half graben structures that formed through rifting with the break-up of Gondwanaland. The model also revealed that these faults segregate the reservoir further creating bigger compartments. The reservoir is highly compartmentalized which will explain the pressure loss within the E-M suite. The production well was drilled within one of these compartments and when the confining pressure was relieved the pressure dropped and the production decrease. As recommendation, additional wells are required to appraise the E-M structure and determine to what extent the granulation seems has affected fluid flow as well as the degree of sedimentation that could impede fluid flow. There are areas still containing untapped resources thus the recommendation for extra wells.

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Hecht, Christian A. "Multi-scale, structural analysis of geomechanical and petrophysical properties of Permocarboniferous red beds Vielskalige Strukturanalyse der geomechanischen und petrophysikalischen Eigenschaften von Permokarbonischen red beds /." [S.l. : s.n.], 2003. http://deposit.ddb.de/cgi-bin/dokserv?idn=971623821.

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Williams, Adrian. "Reservoir Characterization of well A-F1, Block 1, Orange Basin, South Africa." University of the Western Cape, 2018. http://hdl.handle.net/11394/6364.

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Magister Scientiae - MSc (Earth Science)
The Orange basin is relatively underexplored with 1 well per every 4000km2 with only the Ububhesi gas field discovery. Block 1 is largely underexplored with only 3 wells drilled in the entire block and only well A?F1 inside the 1500km2 3?D seismic data cube, acquired in 2009. This study is a reservoir characterization of well A?F1, utilising the acquired 3?D seismic data and re?analysing and up scaling the well logs to create a static model to display petrophysical properties essential for reservoir characterization. For horizon 14Ht1, four reservoir zones were identified, petro?physically characterized and modelled using the up scaled logs. The overall reservoir displayed average volume of shale at 24%, good porosity values between 9.8% to 15.3% and permeability between 2.3mD to 9.5mD. However, high water saturation overall which exceeds 50% as per the water saturation model, results in water saturated sandstones with minor hydrocarbon shows and an uneconomical reservoir.

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Bailey, Carlynne. "Comparative Study of the Chemostratigraphic and Petrophysical characteristics of Wells A-A1, A-L1, A-U1 and A-I1 in the Orange Basin, South Atlantic Margin, Offshore South Africa." Thesis, University of the Western Cape, 2009. http://etd.uwc.ac.za/index.php?module=etd&action=viewtitle&id=gen8Srv25Nme4_1427_1282897265.

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Many hydrocarbon reservoirs are situated in barren sequences that display poor stratigraphic control. Correlation between the wells can become extremely difficult and traditional correlation techniques can prove to be inadequate. Past studies have shown that trace and major element concentrations can be used as a correlation tool. This practice of using geochemical fingerprints to characterize between wells is called Chemostratigraphic analysis. (Pearce et al, 1999) Chemostratigraphy has been recognized as a very important correlation technique as it can be used for rocks of any age, in any geological setting as well as sequences that are traditionally defined as barren. Chemostratigraphic analyses can be used as a means of getting rid of ambiguities within data produced by traditional correlation methods such as Biostratigraphy, Lithostratigraphy and Geophysical Logging. In areas where stratigraphic data is not available it can be used to construct correlation frameworks for the sequences found in the area. The motivation behind this study is that the research is not only worthy of academic investigation, but can also provide the industry with new insights into areas that were previously misunderstood because traditional correlation methods were not adequate. The study area, the Orange basin, is located offshore South Africa and is largely underexplored. The basin, that hosts two gas field namely the Ibhubesi and the Kudu gas fields, has large potential but in the past has not been given due attention with only 34 wells being drilled in the area. The Orange basin has recently been the topic of investigation because of the belief that it may be hosts to more hydrocarbons. This study will utilise Chemostratigraphy to attempt to provide geological information on this relatively under-explored basin. The aim of this research study is to produce a chemostratigraphic framework -scheme for the Orange Basin in order to facilitate reservoir scale interwell correlation. The Objectives of this research study will be to identify chemostratigraphic units or indices, to prove the adequate use of chemostratigraphy as an independent correlation technique and to integrate the chemostratigraphy and petrophysical characteristics of the four wells to facilitate lithological identification.

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Ball, Nathaniel H. Atchley Stacy C. "Depositional and diagenetic controls on reservoir quality and their petrophysical predictors within the Upper Cretaceous (Cenomanian) Doe Creek Member of the Kaskapau Formation at Valhalla Field, Northwest Alberta." Waco, Tex. : Baylor University, 2009. http://hdl.handle.net/2104/5296.

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Binyatov, Elnur. "Sedimentological, Cyclostratigraphic Analysis And Reservoir Characterization Of Balakhany X Formation Within The Productive Series Azeri Field On C01 Well (offshore Azerbaijan)." Master's thesis, METU, 2008. http://etd.lib.metu.edu.tr/upload/3/12609628/index.pdf.

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The Azeri, Chirag, Gunashli (ACG) field is located offshore Azerbaijan. The reservoirs are multilayered sandstones forming traps within a major anticlinal structure. Proven crude oil reserves are estimated to contain 5.4 billion barrels of oil. In the past this area has been studied in regional detail but not at the reservoir scale with respect to the fluvio-deltaic sediments filling the northern shore of the ancient South Caspian Sea. The aim of this study is carried out the sedimentological, cyclostratigraphical analysis and reservoir characterization of Balakhany X Formation within the Productive Series which is considered to be one of the significant producing horizons. To be able to achieve this objective, a 30m thick section, which is mainly composed of siliciclastics, has been studied in detail on Balakhany X cores from C01 well Azeri field. In this study, detailed lithofacies analyses were performed and sandstone, mudstone, siltstone facies were recognized in the studied interval of the Balakhany X Formation. Litharenites and sublitharenites sandstones are the most abundant in the succession. Sedimentological analysis such as grain-size sphericity, provenance, XRD, SEM and grain surface texture were performed and their relationship with depositional environment were discussed. The grain size distribution of the samples along the succession shows distribution of fine to very fine sands. Sorting of sandstones ranges between moderately well to very well sorted. The provenance analysis of sandstones based on modal analysis of thin sections related to recycled orogen. According to interpretation of grain size parameters and grain surface textures analysis the main transporting agent of sands observed as wind, wave and river agents. High resolution cyclostratigraphy studies based on cm-m scaled cyclic occurrences of lithofacies along the measured section were performed. Milankovitch, sub-Milankovitch and millennial cycles were determined along the studied section. The petrophysical analysis revealed good to very good (18 to 24%) porosity and good permeability (10 to 538mD) in Balakhany X Formation. The porosity and permeability are affected by both textural and compositional controls. Grain size distribution along the reservoir section is fine to very fine sands. Influence of compaction was observed by the fractures and dissolutions on the sand grains. The calcite cement, grain-size variation, sorting and compaction are the main factors controlling porosity and permeability.

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Jouini, Mohamed Soufiane. "Caractérisation des réservoirs basée sur des textures des images scanners de carottes." Thesis, Bordeaux 1, 2009. http://www.theses.fr/2009BOR13769/document.

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Les carottes, extraites lors des forages de puits de pétrole, font partie des éléments les plus importants dans la chaîne de caractérisation de réservoir. L’acquisition de celles-ci à travers un scanner médical permet d’étudier de façon plus fine les variations des types de dépôts. Le but de cette thèse est d’établir les liens entre les imageries scanners 3D de carottes, et les différentes propriétés pétrophysiques et géologiques. Pour cela la phase de modélisation des images, et plus particulièrement des textures, est très importante et doit fournir des descripteurs extraits qui présentent un assez haut degrés de confiance. Une des solutions envisagée pour la recherche de descripteurs a été l’étude des méthodes paramétriques permettant de valider l’analyse faite sur les textures par un processus de synthèse. Bien que ceci ne représente pas une preuve pour un lien bijectif entre textures et paramètres, cela garantit cependant au moins une confiance en ces éléments. Dans cette thèse nous présentons des méthodes et algorithmes développés pour atteindre les objectifs suivants : 1. Mettre en évidence les zones d’homogénéités sur les zones carottées. Cela se fait de façon automatique à travers de la classification et de l’apprentissage basés sur les paramètres texturaux extraits. 2. Établir les liens existants entre images scanners et les propriétés pétrophysiques de la roche. Ceci se fait par prédiction de propriétés pétrophysiques basées sur l’apprentissage des textures et des calibrations grâce aux données réelles.
Cores extracted, during wells drilling, are essential data for reservoirs characterization. A medical scanner is used for their acquisition. This feature provide high resolution images improving the capacity of interpretation. The main goal of the thesis is to establish links between these images and petrophysical data. Then parametric texture modelling can be used to achieve this goal and should provide reliable set of descriptors. A possible solution is to focus on parametric methods allowing synthesis. Even though, this method is not a proven mathematically, it provides high confidence on set of descriptors and allows interpretation into synthetic textures. In this thesis methods and algorithms were developed to achieve the following goals : 1. Segment main representative texture zones on cores. This is achieved automatically through learning and classifying textures based on parametric model. 2. Find links between scanner images and petrophysical parameters. This is achieved though calibrating and predicting petrophysical data with images (Supervised Learning Process)

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Chadouli, Kheira. "Caractérisation pétrographique appliquée à la modélisation pétrolière : étude de cas." Thesis, Université de Lorraine, 2013. http://www.theses.fr/2013LORR0291/document.

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La compréhension d'un système pétrolier nécessite la caractérisation pétrographique de tous les éléments et les processus le composant. Dans ce travail, plusieurs exemples de roches mères, roches réservoirs et roches couvertures provenant de bassins pétroliers différents, ont été étudiés afin de décrire les méthodes pétrographique classiques et mettre en place des nouvelles. Ces dernières telles que : la création d'une cinétique de transformation d'un kérogène composé de deux types de matière organiques (programmation), analyse macérale et l'étude des microfractures par analyse d'images, la diffraction à rayon X ainsi que la tomographie ont permis la caractérisation de la roche mère. Quant aux roches réservoirs, les méthodes d'analyse d'image des propriétés pétrophysiques, la microscopie MSCL ainsi que les paramètres de mouillabilité permettent la description de la qualité de ces réservoirs et leurs préservations au cours du temps à cause des phénomènes de recristallisation, dissolution, circulation de fluide et de réaction TSR/BSR. Les roches couvertures étudiées dans ce travail sont celles des argilites callovo-oxfordienne, utilisant la diffraction à rayon X ainsi que l'analyse d'image et la tomographie. Ces méthodes ont facilité la compréhension de leurs comportements au cours du temps, leurs capacités de sorption/désorption et leurs fiabilités de stockage de déchets nucléaire. Enfin, la modélisation pétrolière avec Petromod permet de déterminer les fonctionnements des systèmes pétroliers. La modélisation par percolation est plus proche de la réalité des bassins pétroliers que celle de Darcy/Hybride
Understanding oil systems requires petrographic characterization of all elements and process that compose it. In this work, several examples of source rocks, reservoir rocks and seal from different petroleum basins have been studied in order to describe conventional petrographic methods and develop new ones. The new ones as: a program of transformation kinetic of kerogene composed of two types of organic matter, maceral analysis and microfractures study using images analysis, the diffraction X-ray and tomography allowed source rock description. As for, reservoir rocks, methods of petrophysical characterization by images analysis, MSCL Microscopy and wettability parameters permit reservoir quality description and their preservation over time due to recrystalization and dissolution phenomena, fluid flow and TSR/BSR reaction. The cap rocks studied in this thesis are those of Callovo-Ordovician argillites, using X-Ray diffraction as well as images analysis and tomography. Those methods facilitated the understanding of argillites behavior over time, their sorption/desorption ability and their reliability of nuclear waste storage. Finally, Modeling using Petromod helps to determine petroleum systems functioning. Modeling by percolation method gives results closer to oil basins reality, than by Darcy/Hybrid method

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Turmel, Aurélie. "Répartition et utilisation des pierres et géomatériaux de construction dans le bâti du Pays rémois - analyse spatiale et propriétés pétrophysiques -." Thesis, Reims, 2014. http://www.theses.fr/2014REIMS022/document.

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Les relations entre l'utilisation, l'origine et les propriétés des matériaux de construction peuvent être définies comme des éléments de cohésion territoriale. Elles sont en outre des questions inhérentes à la conservation et restauration du patrimoine culturel. L'objectif de ce travail est d'évaluer cette relation dans le Pays rémois (Bassin Parisien, France). Ce dernier est un exemple concret de zone d'étude limitée (1 400 km², 140 communes) mais dotée d'une géologie et d'un patrimoine très variés. 26 matériaux de construction différents (craie, grès, calcaires, meulière et briques etc.) ont été décrits macroscopiquement et recensés afin de construire une base de données géoréférencées (via ArGis®). Leurs répartitions spatiales ont été analysées à l'aide d'outils de distribution et d'autocorrélation. Par ailleurs, des caractérisations pétrophysiques ont été réalisées en laboratoire sur une sélection de calcaires lutétiens. Les résultats montrent une cohésion territoriale d'utilisation des matériaux répartie selon 6 microrégions et une évolution de leur utilisation du XIe au XXe siècle. La diversité pétrophysique des matériaux du Lutétien est importante, avec différents niveaux de sensibilité aux sels et au gel. L'étude apporte des clefs pour comprendre les critères de choix des matériaux et des conseils pour la gestion du patrimoine dans le territoire d‘étude
The relationship between uses, origins and properties of building materials can be defined as an element of territorial cohesion of. This is an inherent matter of the preservation and restoration of the cultural heritage. The aim of the study was to highlight this relationship in The Pays rémois (Paris Basin, France). This is a specific zone of 1400 km² with around 140 villages, with an important geological and historical background. Twenty-six building materials (chalk, sandstones, limestones, cherts and bricks) were macroscopically described and field observations werecompiled in a GIS-database (via Arcgis®). Repartition analyses were made with distribution and spatial autocorrelation tools. Petrophysical characterizations were realized on selected lutetian limestones. Results showed 6 areas of building material uses and temporal tendencies use from XIe to XXe centuries. Petrophysical datas were very different between and inside these four limestone groups. Their salt and freeze durability were variable too. The study highlighted some clues to understand choice criteria of building stones and provided guidance for the management and restoration in the Pays rémois

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Mugivhi, Murendeni Hadley. "Integration of petrographic and petrophysical logs analyses to characterize and assess reservoir quality of the lower cretaceous sediments in the Orange basin, offshore south africa." University of the Western Cape, 2017. http://hdl.handle.net/11394/5678.

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Magister Scientiae - MSc
Commercial hydrocarbon production relies on porosity and permeability that defines the storage capacity and flow capacity of the resevoir. To assess these parameters, petrographic and petrophysical log analyses has been found as one of the most powerful approach. The approach has become ideal in determining reservoir quality of uncored reservoirs following regression technique. It is upon this background that a need arises to integrate petrographic and petrophysical well data from the study area. Thus, this project gives first hand information about the reservoir quality for hydrocarbon producibility. Five wells (A-J1, A-D1, A-H1, A-K1 and K-A2) were studied within the Orange Basin, Offshore South Africa and thirty five (35) reservoirs were defined on gamma ray log where sandstone thickness is greater than 10m. Eighty three (83) sandstone samples were gathered from these reservoirs for petrographic analyses within Hauterevian to Cenomanian sequences. Thin section analyses of these sediments revealed pore restriction by quartz and feldspar overgrowths and pore filling by siderite, pyrite, kaolinite, illite, chlorite and calcite. These diagenetic minerals occurrence has distructed intergranular pore space to almost no point count porosity in well K-A2 whilst in A-J1, A-D1, A-H1 and A-K1 wells porosity increases at some zones due to secondary porosity. Volume of clay, porosity, permeability, water saturation, storage capacity, flow capacity and hydrocarbon volume were calculated within the pay sand interval. The average volume of clay ranged from 6% to 70.5%. The estimated average effective porosity ranged from 10% to 20%. The average water saturation ranged from 21.7% to 53.4%. Permeability ranged from a negligible value to 411.05mD. Storage capacity ranged from 6.56 scf to 2228.17 scf. Flow capacity ranged from 1.70 mD-ft to 31615.82 mD-ft. Hydrocarbon volume varied from 2397.7 cubic feet to 6215.4 cubic feet. Good to very good reservoir qualities were observed in some zones of well A-J1, A-K1 and A-H1 whereas well A-D1 and K-A2 presented poor qualities.

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Linoir, Damien. "Les horizons d'accumulations carbonatées en Champagne-Ardenne : répartition régionale, caractérisation et impact sur les transferts hydriques." Thesis, Reims, 2014. http://www.theses.fr/2014REIMS030/document.

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Les horizons d'accumulations carbonatées (HAC) de Champagne sont des horizons particuliers présents de manière non systématique dans les profils de sol directement sous l'horizon organo-minéral. Bien que des travaux antérieurs se soient déjà attachées à l'étude de ces structures particulières, certaines questions restent encore en suspens, notamment en ce qui concerne leur localisation dans le cadre régional, leur caractérisation par rapport aux autres horizons du profil et la quantification de leur rôle dans les transferts hydriques. Leur localisation sur le terrain n'étant pas réalisable méthodes de prospection habituelles (pénétrométrie dynamique, tarière), les zones de localisation préférentielle des HAC ont été déterminées par une exploration bibliographique. Des analyses en laboratoire ont été conduites sur des échantillons prélevés sur un site pilote représentatif, le Mont du Ménil (08). En plus des analyses géochimiques et de la colorimétrie, les échantillons prélevés tout au long des profils ont subi des analyses pétrophysiques habituellement utilisées dans la caractérisation des pierres en œuvre (porosité totale à l'eau, porosimétrie mercure, cinétiques d'absorptions capillaires et d'évaporation). Ces analyses montrent que les HAC sont bien différents des horizons sus et sous-jacents. Ce sont des niveaux présentant une forte porosité qui va de pair avec leur induration plus faible contrairement à ce qui est généralement admis dans la bibliographie. Les HAC présentent également des micromorphologies différentes des autres horizons du profil pédologique ce qui justifient les réseaux poreux différents identifiés. L'étude des transferts hydriques en laboratoire montre également que ces réseaux poreux différents sont responsables de transferts hydriques plus rapides dans les HAC que dans leurs grèzes d'accueil. Il apparaît donc que contrairement à ce qui est généralement avancé dans la littérature, les HAC champardennais ne semblent pas faire obstacle aux transferts hydriques mais semble au contraire les favoriser. Ce phénomène pourrait avoir des conséquences agronomiques importantes favorisant le drainage et les remontées capillaires
Carbonate accumulation horizons (CAH) are structures un-systematically present in Champagne-Ardenne soils (NE of France) and are localized directly under de rendic leptosol. They have already been studied but their regional repartition, characterization compare to other soils horizons and impact on water transfers remain unknown. On the field, CAH cannot be directly localized by currently prospection methods. Preferential location areas have been determined by literature analyze. Geochemistry, colorimetry and petrophysical analyzes (total water porosity, mercury porosimetry, absorption en evaporation kinetics tests) have been applied on samples took on a representative site : Mont du Ménil. These analyses have shown that CAH present a high porosity linked to their weak induration contrary to what is generally advanced in the literature. The micromorphology of CAH is different from others horizons that induces porous network différences. Laboratory water transfers study links these porous network differences to faster water transfers measured for CAH contrary to the others horizons. CAH of Champagne do not impede water transfers contrary to what is generally fund into the literature but seems to favor them. This phenomenon could have important agronomic implications favouring draining and capillary rises

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Dicus, Christina Marie. "Relationship between pore geometry, measured by petrographic image analysis, and pore-throat geometry, calculated from capillary pressure, as a means to predict reservoir performance in secondary recovery programs for carbonate reservoirs." [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-2076.

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Rippen, Daniel Verfasser], Ralf [Akademischer Betreuer] [Littke, and Brian [Akademischer Betreuer] Horsfield. "Oil and gas shales of Northern Germany : implications from organic geochemical analyses, petrophysical measurements and 3D numerical basin modelling / Daniel Rippen ; Ralf Littke, Brian Horsfield." Aachen : Universitätsbibliothek der RWTH Aachen, 2015. http://d-nb.info/1130327094/34.

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Butterfield, Andrei. "Characterization of a Utica Shale Reflector Package Using Well Log Data and Amplitude Variation with Offset Analysis." Wright State University / OhioLINK, 2014. http://rave.ohiolink.edu/etdc/view?acc_num=wright1401462908.

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Bruned, Vianney. "Analyse statistique et interprétation automatique de données diagraphiques pétrolières différées à l’aide du calcul haute performance." Thesis, Montpellier, 2018. http://www.theses.fr/2018MONTS064.

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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

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Salimifard, Babak. "Predicting permeability from other petrophysical properties." 2015. http://hdl.handle.net/1993/30645.

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Understanding pore network structure of a porous medium and fluid flow in the pore network has been an interest to researchers for decades. This study focuses on the characterization and simulation of the pore networks in petroleum reservoir rocks using conventional characterization techniques. A Representative Elemental Volume (REV) model is developed which simulates the pore network as a series of non-interconnected capillary tubes of varying sizes. The model implements mercury porosimetry (MP) results and capillary pressure principles to calculate the size of each bundle of capillary tubes based on a pore throat size distribution produced by the MP experiment. It also implements electrical properties of the rocks to estimate the average length of the capillary tubes. To verify the validity of the simulated network, permeability is calculated for the simulated network using Poiseuille’s flow principles for capillary tubes. Preliminary work showed that the model is capable of simulating the pore network reasonably well because permeability estimations for the simulated network matched measurements. In this study, MP and nuclear magnetic resonance (NMR) tests as well as centrifuge and permeability tests are performed on a suite of 11 sandstone and carbonate rock samples. Because electrical tests were not available, average length of flow paths is calculated with an alternative method that uses porosity to calculate tortuosity. Permeability estimations of the simulated network are compared with measurements. Estimations are also compared to other predictions using methods that implement MP and NMR data to simulate the pore network and the results show that the developed REV model out performs all the other techniques.
October 2015

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Richardson, Paul. "Petrophysical analysis of the lower Lance formation, Washakie Basin, Wyoming." 2009. http://digital.library.okstate.edu/etd/Richardson_okstate_0664M_10527.pdf.

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Xu, Chicheng. "Reservoir description with well-log-based and core-calibrated petrophysical rock classification." 2013. http://hdl.handle.net/2152/21315.

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Rock type is a key concept in modern reservoir characterization that straddles multiple scales and bridges multiple disciplines. Reservoir rock classification (or simply rock typing) has been recognized as one of the most effective description tools to facilitate large-scale reservoir modeling and simulation. This dissertation aims to integrate core data and well logs to enhance reservoir description by classifying reservoir rocks in a geologically and petrophysically consistent manner. The main objective is to develop scientific approaches for utilizing multi-physics rock data at different time and length scales to describe reservoir rock-fluid systems. Emphasis is placed on transferring physical understanding of rock types from limited ground-truthing core data to abundant well logs using fast log simulations in a multi-layered earth model. Bimodal log-normal pore-size distribution functions derived from mercury injection capillary pressure (MICP) data are first introduced to characterize complex pore systems in carbonate and tight-gas sandstone reservoirs. Six pore-system attributes are interpreted and integrated to define petrophysical orthogonality or dissimilarity between two pore systems of bimodal log-normal distributions. A simple three-dimensional (3D) cubic pore network model constrained by nuclear magnetic resonance (NMR) and MICP data is developed to quantify fluid distributions and phase connectivity for predicting saturation-dependent relative permeability during two-phase drainage. There is rich petrophysical information in spatial fluid distributions resulting from vertical fluid flow on a geologic time scale and radial mud-filtrate invasion on a drilling time scale. Log attributes elicited by such fluid distributions are captured to quantify dynamic reservoir petrophysical properties and define reservoir flow capacity. A new rock classification workflow that reconciles reservoir saturation-height behavior and mud-filtrate for more accurate dynamic reservoir modeling is developed and verified in both clastic and carbonate fields. Rock types vary and mix at the sub-foot scale in heterogeneous reservoirs due to depositional control or diagenetic overprints. Conventional well logs are limited in their ability to probe the details of each individual bed or rock type as seen from outcrops or cores. A bottom-up Bayesian rock typing method is developed to efficiently test multiple working hypotheses against well logs to quantify uncertainty of rock types and their associated petrophysical properties in thinly bedded reservoirs. Concomitantly, a top-down reservoir description workflow is implemented to characterize intermixed or hybrid rock classes from flow-unit scale (or seismic scale) down to the pore scale based on a multi-scale orthogonal rock class decomposition approach. Correlations between petrophysical rock types and geological facies in reservoirs originating from deltaic and turbidite depositional systems are investigated in detail. Emphasis is placed on the cause-and-effect relationship between pore geometry and rock geological attributes such as grain size and bed thickness. Well log responses to those geological attributes and associated pore geometries are subjected to numerical log simulations. Sensitivity of various physical logs to petrophysical orthogonality between rock classes is investigated to identify the most diagnostic log attributes for log-based rock typing. Field cases of different reservoir types from various geological settings are used to verify the application of petrophysical rock classification to assist reservoir characterization, including facies interpretation, permeability prediction, saturation-height analysis, dynamic petrophysical modeling, uncertainty quantification, petrophysical upscaling, and production forecasting.
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Ijasan, Olabode. "Inversion-based petrophysical interpretation of logging-while-drilling nuclear and resistivity measurements." 2013. http://hdl.handle.net/2152/21390.

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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.
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Adigozalova, Teyyuba. "High-resolution sedimentological, petrographic, and petrophysical analysis of Late Oxfordian - Early Kimmeridgian (?), Ulayyah Member, Hanifa Formation: Insights from behind-the-outcrop core WB-01." Thesis, 2021. http://hdl.handle.net/10754/671358.

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The Hanifa Formation has a high-economic value in Saudi Arabia and many middle-eastern countries where it exists both as a reservoir and source rock. A few examples of the super-giant oil and gas fields that have Hanifa reservoir in the subsurface include Berri and Khurais fields. In this project, an analogue core for Hanifa reservoir facies that was drilled behind-the-outcrop, ~ 150 km south of Riyadh, along the Tuwaiq Mountain escarpment is studied. The main objective of this study is to analyze the vertical facies heterogeneity of Ullayah Member of Hanifa Formation. Thus, for this study sedimentological, petrographical, and petrophysical data have been collected and analyzed at a very high resolution. Based on the sedimentological, petrophysical and petrographic interpretation, four different vertical facies associations can be defined, representing distinct depositional environments (vertically): 1) High energy-level proximal shoreline, intraclastic grainstones deposition with moderate-Vp, relatively low-GR signature ; 2) Relatively low energy-level lagoonal depositional setting with low-Vp, high-GR represented by wackestones/packstones that has lagoonal microfossils and dasyclad algae; 3) Back barrier reefal depositional setting with moderate Vp, low-GR signature represented by stromatoporoids and corals, and 4) Oncoidal depositional setting with moderate-Vp, low- GR signature, mainly composed of ellipsoidal oncoids. Overall, the facies from these environments have been systematically vertically stacked on top of each other (in core WB-01), representing a deepening upwards trend and followed by shallowing oncoidal facies. This interpretation is also well match in regional context (GR data) and can be used as correlation reference.

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Isdiken, Batur. "Integrated geological and petrophysical investigation on carbonate rocks of the middle early to late early Canyon high frequency sequence in the Northern Platform area of the SACROC Unit." 2013. http://hdl.handle.net/2152/23212.

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The SACROC unit is an isolated carbonate platform style of reservoir that typifies a peak icehouse system. Icehouse carbonate platforms are one of the least well understood and documented carbonate reservoir styles due to the reservoir heterogeneities they embody. The current study is an attempt to recognize carbonate rock types defined based on rock fabrics by integrating log and core based petrophysical analysis in high-frequency cycle (HFC) scale sequence stratigraphic framework and to improve our ability to understand static and dynamic petrophysical properties of these reservoir rock types, and there by, improve our understanding of heterogeneity in the middle early to late early Canyon (Canyon 2) high frequency sequence (HFS) in the Northern Platform of the SACROC Unit. Based on core descriptions, four different sub-tidal depositional facies were defined in the Canyon 2 HFS. Identified depositional facies were grouped into three different reservoir rock types in respect to their rock fabrics in order for the HFC scale petrophysical reservoir rock type characteristic analysis. Composed of succession of the identified reservoir rocks, twenty different HFCs were determined within the HFC scale sequence stratigraphic framework. The overall trend in the HFCs demonstrate systematic coarsening upward cycles with high reservoir quality at the cycle tops and low reservoir quality at the cycle bottoms. It was observed in terms of systems tracts described within the cycle scale frame work that the overall stacking pattern for high stand systems tracts (HST) and transgressive systems tracts (TST) is aggradational. And, the reservoir rocks representing the HST are more porous and permeable than those of TST. In addition to that, it was detected that the diagenetic overprint on the HST reservoir rocks is more than that of the TST. According to the overall petrophysical observations, the grain-dominated packstone deposited during HST was interpreted as the best reservoir rock. Upon well log analysis on the identified reservoir rocks, some specific log responses were attributed to the identified reservoir rocks as their characteristic log signatures.
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Hecht, Christian A. [Verfasser]. "Multi-scale, structural analysis of geomechanical and petrophysical properties of Permocarboniferous red beds = Vielskalige Strukturanalyse der geomechanischen und petrophysikalischen Eigenschaften von Permokarbonischen red beds / von Christian A. Hecht." 2003. http://d-nb.info/971623821/34.

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Šálek, Ondřej. "Korektorské vlastnosti sedimentárních hornin z karotážních měření." Master's thesis, 2013. http://www.nusl.cz/ntk/nusl-321097.

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3 ABSTRACT The work is focused on analysis of five structural well profiles penetrating sediments of the Bohemian Cretaceous Basin and the underlying Upper Palaeozoic continental basins to the crystalline basement. The objectives of well profile analysis are sedimentary formation evaluation from well log analysis and statistical analysis and evaluation of some physical properties of sedimentary rocks, which have been determined by measurements of drill cores. The aim of the work is to verify the possibility of porosity evaluation from well log analysis in the Bohemian Cretaceous Basin and the underlying Upper Palaeozoic continental basins. The next aim is to compare different geological environments with respect to physical properties of rocks. The content of the work involves presentation of well log curves, computation of porosity values and comparison between the resulting values of porosity from resistivity log, acoustic log and neutron-neutron log and from laboratory measurements of drill core samples. Data from five deep structural wells are used. Different geological environments were compared by statistical methods with respect to physical properties of rocks measured on well core samples from these five wells. Porosity evaluation from well log analysis is difficult but it is possible provided that...

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Ile, Anthony. "Petrophysics and fluid mechanics of selected wells in Bredasdorp Basin South Africa." 2013. http://hdl.handle.net/11394/3573.

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Magister Scientiae - MSc
Pressure drop within a field can be attributed to several factors. Pressure drop occurs when fractional forces cause resistance to flowing fluid through a porous medium. In this thesis, the sciences of petrophysics and rock physics were employed to develop understanding of the physical processes that occurs in reservoirs. This study focussed on the physical properties of rock and fluid in order to provide understanding of the system and the mechanism controlling its behaviour. The change in production capacity of wells E-M 1, 2, 3, 4&5 prompted further research to find out why the there will be pressure drop from the suits of wells and which well was contributing to the drop in production pressure. The E-M wells are located in the Bredasdorp Basin and the reservoirs have trapping mechanisms of stratigraphical and structural systems in a moderate to good quality turbidite channel sandstone. The basin is predominantly an elongated north-west and south-east inherited channel from the synrift sub basin and was open to relatively free marine circulation. By the southwest the basin is enclose by southern Outeniqua basin and the Indian oceans. Sedimentation into the Bredasdorp basin thus occurred predominantly down the axis of the basin with main input direction from the west. Five wells were studied E-M1, E-M2, E-M3, E-M4, and E-M5 to identify which well is susceptible to flow within this group. Setting criteria for discriminator the result generated four well as meeting the criteria except for E-M1. The failure of E-M1 reservoir well interval was in consonant with result showed by evaluation from the log, pressure and rock physics analyses for E-M1.iv Various methods in rock physics were used to identify sediments and their conditions and by applying inverse modelling (elastic impedance) the interval properties were better reflected. Also elastic impedance proved to be an economical and quicker method in describing the lithology and depositional environment in the absence of seismic trace.

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Stück, Heidrun Louise. "Dimensional Sandstones: Weathering Phenomena, Technical Properties and Numerical Modeling of Water Migration." Thesis, 2013. http://hdl.handle.net/11858/00-1735-0000-0020-E940-B.

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