Dissertations / Theses: 'Petroleum reservoirs'

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Yacob, Shahrakbah, and n/a. "Metal-reducing microorganisms in petroleum reservoirs." University of Canberra. Resource & Environmental Science, 2000. http://erl.canberra.edu.au./public/adt-AUC20061112.102729.

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Metal-reducing microorganisms reduce a variety of metals in metabolic processes coupled to the oxidation of organic compounds. These bacteria play an important role in the biogeochemical cycling of metals and organic matter in anaerobic aquatic and sediment ecosystems. It has been proposed recently that metal-reducing microorganisms also are active in deep subsurface environments such as petroleum reservoirs. Only two metal-reducing bacteria have been isolated from petroleum reservoir fluids, Shewanella putrefaciens and Deferribacter thermophilus. This project studied the occurrence and distribution of metal-reducing microorganisms in petroleum reservoirs. The research focused on the isolation, characterisation and identification of anaerobic bacteria from petroleum reservoirs that were capable of reducing metals and the potential roles of these isolates in the microbial ecology and biogeochemical cycling of petroleum reservoirs. Petroleum reservoirs were selected for this study on the basis of physio-chemical conditions such as temperature, salinity, pH and the presence of organic and inorganic compounds, that were likely to provide a suitable environment for anaerobic bacteria capable of reducing metals. Factors such as the stratigraphic features of the sedimentary basin, age of reservoir and past oil field practices also were considered in choosing the reservoir for study. Seven petroleum reservoirs in the USA and Azerbaijan were chosen for extensive investigations. The physico-chemical conditions in these reservoirs varied substantially. A systematic study of the production water from these petroleum reservoirs revealed a consistent presence of iron- and manganese-reducing microorganisms. It was found that salinity and temperature play a significant and defining role in the occurrence and distribution of these metal-reducing microorganisms. Biotic metal reduction was detected from production waters from all but one of the oil wells sampled. It was significant that the water from this well (Neftcala #1074) was the most saline (78 g/l NaCI). Metal-reducing activity was detected at temperatures up to 70°C. Two pure cultures, strains RED1 for Redwash petroleum reservoir (USA) and NEF1 from the Neftcala petroleum reservoir (Azerbaijan) were isolated and characterized. The strains had diverse physiological and metabolic properties including the ability to oxidize a wide range of carbon compounds and reduce a variety of metals. Their temperature, salinity and pH optima varied markedly. Phylogenetic analyses of the 16S rRNA of strain RED1 showed that the strain represented a new species of a new genus in the domain Bacteria. The bacterium most closely related to strain RED1 is the fermentative Fe(III)-reducer, Pelobacter acetylenicus (similarity value, 92.8%). Strain NEF1 possesses a unique combination of phenotypic traits and a low mol % G+C. From preliminary analyses and comparative biochemistry, NEF1 appears to be a novel metal-reducing bacterium of the Flexistipes group. The bacteria isolated in this study were able to grow at temperatures and salinities consistent with the reservoir from which they were isolated. This indicated that petroleum reservoirs are a new source of physiologically diverse, novel, metal-reducing microorganisms. The bacteria isolated also demonstrated a number of characteristics that would enable them to survive and persist in extreme subsurface conditions and develop a selective ecological advantage in petroleum reservoir environments. Significantly, the metal-reducing bacteria isolated were able to utilize an array of metabolic products produced by bacteria indigenous to petroleum reservoirs. This has resulted in a new proposed model for the ecological succession of bacteria in petroleum reservoirs.

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SOUZA, ANTONIO LUIZ SERRA DE. "STUDY OF HEAT LOSSES IN PETROLEUM RESERVOIRS." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 1988. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=20366@1.

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PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO
PETRÓLEO BRASILEIRO S. A.
Neste trabalho analisam-se perdas de calor para as formações adjacentes a reservatórios de petróleo submetidos a métodos térmicos de recuperação, em especial para os métodos de injeção de vapor e combustão in-situ. O cálculo desta perda usualmente utiliza um modelo unidimensional vertical de condução de calor nos estratos adjacentes, desprezando a condução nas direções paralelas ao reservatório. O objetivo do trabalho consiste em avaliar diversos modelos unidimensionais existentes na literatura e desenvolver e utilizar modelos bidimensionais para verificar a validade da hipótese. Verifica-se que para algumas situações de injeção Cíclica de Vapor e Combustão in-situ o modelo uni-dimensional pode levar a diferenças no campo de temperaturas, mas em geral a aproximação é válida.
In this work the calculation of the heat losses to the surrouinding formations in petrolum reservouis submitted to thermal recovery processes is analyzed. Particular attention is given to steam injection an in-situ combustion methods. The heat losses are commonly modeled by the use of a unidimensional conduction equation in the vertical direction, where the longitudinal conduction is neglected. The aim of thus work is to compare some of the existing unidemnsional models and to test the validity of the simplification by the development and use of bidimensional ones. Its is concluded that for some cases of cyclic steam injection and in-situ combustion the unidimensional approach may result in deviations in the temperature profiles, but in general it is valid.

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Grassia, Gino Sebastian, and n/a. "The isolation, growth and survival of thermophilic bacteria from high temperature petroleum reservoirs." University of Canberra. Applied Science, 1995. http://erl.canberra.edu.au./public/adt-AUC20060712.131412.

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The microbial ecology of 45 high temperature (> 50 ° C) petroleum reservoirs was investigated by isolating and characterizing bacteria that were present in their produced fluids. Initial work was aimed at selecting a suitable high temperature petroleum reservoir for the study of natural microbial populations. Experimental work then focussed on establishing the physico-chemical conditions that prevail in the selected reservoir and on developing media and enrichment conditions for the isolation of microorganisms indigenous to the reservoir. The ability of reservoir bacteria to grow and survive under the physical and chemical conditions found in the selected reservoir was used to assess the likelihood of an indigenous origin for these bacteria. The petroleum reservoir selected for study was the Alton petroleum reservoir (SW Queensland, Australia). It was established that most of the physico-chemical conditions in the Alton reservoir had remained unchanged since oil recovery began. The stability of redox conditions (90 mV) in the reservoir over its operating life was identified as an important factor in the coexistence of strict aerobic and strict anaerobic bacterial populations within the reservoir. An important change that has occurred in the Alton reservoir over its operating life because of oil recovery was an increase in water pH from 6.41 to 8.42 as a result of carbon dioxide loss (1.36 atm to 0.0134 atm) from the reservoir. Development of novel enrichment procedures that simulated Alton reservoir conditions led to the isolation of previously unreported aerobic and anaerobic populations of thermophilic bacteria. The aerobic bacteria isolated were identified as either endosporeforming heterotrophic bacteria from the genus Bacillus or nonspore-forming heterotrophic bacteria resembling members of the genus Thermoleophilum. All aerobes grew on carbon sources such as acetate and n-heptadecane that are normal constituents of the reservoir. The anaerobic bacteria isolated were characterized as sheathed fermentative bacteria from the order Thermotogales or non-sheathed fermentative bacteria. In parallel studies, the natural microbial populations in other reservoirs were investigated and I concluded that fermentative microorganisms were common inhabitants of high temperature petroleum reservoirs. The isolation of fermentative bacteria from these high temperature petroleum reservoirs established that fermentative bacteria are a fourth major microbial group, together with hydrocarbon-oxidizers, sulphate-reducers and methanogens, to be reported in petroleum reservoirs. The fermentative bacteria use organic nutrients and carbohydrates, but not contemporary crude oil as the principal nutrient source within reservoir waters. The thermophilic bacteria isolated from Alton petroleum reservoir demonstrated growth characteristics such as temperature (optima 50-70 ° C and range 37-85 ° C), pH (optima 6.0-9.0 and range 5.0-9.0 and salinity (optima 0-15 g per litre and range 0-30 g per litre), that were consistent with conditions encountered in the Alton reservoir (temperature 75 � C, pH 8.5 and TDS 2.7 g per litre). The isolated bacteria also demonstrated a number of characteristics that might enable them to survive adverse conditions that could be encountered in a petroleum reservoir environment. The characteristics that contribute to aerobic bacteria surviving in and overcoming periods of oxygen limitation include well-documented processes such as sporulation, by Bacillus spp., and microaerophily. The characteristics that contribute to fermentative bacteria surviving were: (1) a natural tolerance to reservoir physico-chemical fluctuations, (2) an ability to remain viable when metabolic activity was suppressed to very low rates by the growth-limiting conditions imposed, and (3) possible formation of viable ultramicrobacteria (UMB). Formation of UMB (bacteria smaller than 0.3 |im) by thermophilic bacteria has not been reported previously. The recovery of thermophilic UMB by filtration from the Alton reservoir water indicates that these bacteria occur in natural habitats. This study found the formation of thermophilic UMB and their survival characteristics differed considerably from that reported for the mesophilic, marine bacterium Vibrio sp. DWI. Unlike mesophilic marine bacteria, thermophilic bacteria did not always respond to nutrient deprivation by forming UMB and that these UMB did not show any increased ability to survive in the face of adverse conditions. Although the formation of UMB as part of routine cell growth and division was not demonstrated directly in this study, circumstantial evidence suggests that they form part of a natural life cycle. The exact conditions that result in UMB formation and their role in survival remain unresolved. The capacity of nonspore-forming indigenous populations from Alton to survive sudden shifts in environmental conditions that might result from common oilfield operations was poor. Such operations were demonstrated to be inhibitory or lethal to Alton reservoir bacteria. It also was concluded that such oilfield operations suppress indigenous microbiota. However, the impacts of most oilfield operations within a reservoir are likely to be confined to the immediate area surrounding injection and producing wells. Minimizing the localized effects of oilfield practices on indigenous reservoir populations will lead to the better management of undesirable microbial activity in reservoirs such as H2S formation (souring) and facilitate development of better microbially mediated oil recovery process. This study showed that selected reservoir isolates possess characteristics which are suitable for in situ biotechnological applications such as microbially enhanced oil recovery (MEOR). Characteristics favourable for enhanced oil recovery include a capability for UMB formation, which would enable better dispersion, and resistance to high concentrations of reservoir components such as calcium, magnesium, strontium, heavy metals and hydrocarbons.

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Alkafeef, Saad Feheid. "A study of colloidal asphaltene in petroleum reservoirs." Thesis, Imperial College London, 1997. http://hdl.handle.net/10044/1/11246.

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Hooper, Heather J. (Heather Julie) 1975. "Analysis and modeling of induced seismicity in petroleum reservoirs." Thesis, Massachusetts Institute of Technology, 2002. http://hdl.handle.net/1721.1/54445.

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Thesis (S.M. in Geosystems)--Massachusetts Institute of Technology, Dept. of Earth, Atmospheric, and Planetary Sciences, 2002.
Includes bibliographical references (p. 53).
Since 1998, a producing oil field in Oman has been experiencing microearthquake activity. The aim of this project is to compare numerical models of wave propagation using simple source representations to a small subset of these microearthquakes, with three goals in mind: 1) to understand whether the microearthquakes are generated by movement along a known fault system in the field, or by some other mechanism; 2) if the source is fault related, to better understand what kind of movement is occurring on the fault; and 3) to see if this simple modeling method provides useful results, and forms a basis for future work. Synthetic waveforms are generated using a one-dimensional, discrete wavenumber numerical model (Bouchon, 1980) with two simple source representations: an explosive point source and a vertical force. Comparison of the synthetic waveforms to the microearthquake data indicates that the vertical force results in a better match than the explosive point source. In addition, a simple model consisting of the superposition of four vertical forces (representing vertical fault rupture), results in waveforms that are very similar to the recorded events. These results suggest that the source of the microearthquakes is motion along a near-vertical normal fault system that has been mapped in the field. These results are also consistent with work by Sze and Toksoz (2001) in which relocation of the same events imaged a near-vertical normal fault in the field. Further work using fault rupture source modeling may provide additional insight into the amount of fault motion that is occurring in relation to these events.
by Heather J. Hooper.
S.M.in Geosystems

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Houston, Stephanie Jane. "Formation waters in petroleum reservoirs : their controls and applications." Thesis, University of Leeds, 2007. http://etheses.whiterose.ac.uk/1063/.

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Abundant water chemistry analyses from nine different locations (predominantly petroleum reservoirs) on five continents were evaluated. This information, together with local mineralogy, depth and temperature relations provided a sound basis from which to investigate the most important controls on formation water composition. In particular, the detailed study of two very different hydrocarbon reservoir case studies (the Central US coalbed methane reservoir, the San Juan Basin and the North Sea oilfield Miller) provided an insight not only into the fundamental controls on formation water composition, but also into the effects of active oilfield development on systems that are very sensitive to change on rapid timescales. The geochemistry of San Juan waters is controlled by the introduction of bicarbonate through carbonate dissolution and methane/coal oxidation leading to leaching of Na-bearing clay minerals, and by ion exchange on clay minerals and dilution by meteoric waters in certain locations. The time series of produced waters from Miller enabled detailed study of fluid mixing in the field and the physical, chemical and thermodynamic response of the system to the injection of seawater. Changes occur in the concentrations of many water components through time that cannot be explained by linear mixing between formation water and injected water and require dissolution or precipitation reactions to have occurred between injection and production sites. For example Ba, and SO4 concentrations are affected by equilibrium with barite and what is likely to be sulphate reduction. Also, excess Si present in the fluid is due to dissolution of the silicate phases in the reservoir, and demonstrates reactions between silicate minerals occur on a fast enough timescale to buffer the pH of the water. Integration of all available data shows consistent patterns of behaviour, which implicate mineral-fluid interactions in the subsurface as a major control on formation water chemistry. For example, globally, Ca concentrations are shown to behave in one of three ways, all of which depend on water interaction with the host rock, be it silicate or carbonate, clastic or evaporite. Distinct trends arise for bicarbonate waters, brines derived by halite dissolution and formation brines that have evolved extensively with silicates. In addition, K concentrations are closely related to feldspar-clay equilibria and Mg concentrations are influenced predominantly by carbonate minerals with significant contribution from clays. It is likely that initial Ba concentration is related to interaction with K-feldspars and SO4 is controlled by equilibrium with sulphate mineral phases as well as by redox. A greater understanding of formation water chemistry leads to an improved perception of the importance of these systems in terms of both furthering scientific progress and the technological development of the oil and gas industry. In particular, produced water chemistry analyses from Miller were used to appraise and improve the most important aspects of both generic and specific reservoir models. A set of simple models emphasised the point that small variations in reservoir property parameters can have significant effects on model outputs, and thus the highlighted the importance of thorough reservoir characterisation, particularly permeability heterogeneity, capillary pressure and relative fluid permeabilities. Geochemical models of three different systems from the integrated database (the Alberta Basin, a Colombian onshore oilfield and an oilfield from offshore Gulf of Mexico) illustrate that reservoir rocks containing a wide variety of minerals are the most effective at limiting pH decrease following the injection of CO2 into the system. The geochemistry, in particular the salinity, of the formation water present also has a significant bearing on the processes that are likely to occur during CO2 sequestration.

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Jenkins, C. C. "The organic geochemical correlation of crude oils from early Jurassic to late Cretaceous Age reservoirs of the Eromanga Basin and late Triassic Age reservoirs of the underlying Cooper Basin /." Title page, contents and abstract only, 1987. http://web4.library.adelaide.edu.au/theses/09SM/09smj521.pdf.

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Abdulla, Fawzeiah Hussien Ali. "Source rock evaluation and maturity studies of Lower and Middle Cretaceous formations in Kuwait." Thesis, Imperial College London, 1993. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.312472.

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Ngah, Khalid Bin. "Deposition and diagenesis of Oligocene-Lower Miocene sandstones in the southern Malay Basin." Thesis, Imperial College London, 1990. http://hdl.handle.net/10044/1/46470.

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Taylor, Katherine Sarah. "Ephemeral-fluvial sediments as potential hydrocarbon reservoirs." Thesis, University of Aberdeen, 1994. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=123206.

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Although reservoirs formed from ephemeral-fluvial sandstones have previously been considered relatively simple, unresolved problems of sandbody correlation and production anomalies demonstrate the need for improved understanding of their internal complexity. Ephemeral flows occur in direct response to precipitation, receiving little or no water from springs or other long-continued sources. They consequently predominate in dryland regions where precipitation is high in intensity, short lived and of limited areal extent. Resulting flow is high energy, relatively shallow and also restricted in duration and areal coverage. High transmission losses, abundant loose material and sparse vegetation result in highly concentrated flows which dissipate rapidly, causing a downstream decrease in flow discharge. Sediments deposited from these flows include parallel laminated sands, massive sands, scour-fill sands, transitional lower to upper flow regime dunes, and commonly contain numerous erosional discontinuities, scattered mudclasts, rapid grain size changes and deformational features. Large quantities of rainfall falling over longer periods produces steady flows dominated by well sorted, lower flow regime bedforms which have moderately well developed fining-up sequences. High intensity rainfall falling for shorter periods produces unsteady flows which are characterised by more poorly sorted, upper flow regime bedforms and an absence of fining-up sequences. Outcropping ephemeral-fluvial systems have been studied in order to determine the main features and processes occurring in sand-rich ephemeral systems and to identify which features will be of importance in a hydrocarbon reservoir. The Lower Jurassic Upper Moenave and Kayenta Formations of south-eastern Utah and northern Arizona comprise complex series of stacked, sand-dominated sheet-like palaeochannels suggestive of low sinuosity, braided systems.

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Pecher, Radek. "Boundary element simulation of petroleum reservoirs with hydraulically fractured wells." Thesis, National Library of Canada = Bibliothèque nationale du Canada, 1999. http://www.collectionscanada.ca/obj/s4/f2/dsk1/tape8/PQDD_0018/NQ47908.pdf.

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YAQUETTO, NIURKA PATRICIA RODRIGUEZ. "EVALUATION OF COUPLING SCHEMES IN THE SIMULATION OF PETROLEUM RESERVOIRS." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2011. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=21716@1.

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COORDENAÇÃO DE APERFEIÇOAMENTO DO PESSOAL DE ENSINO SUPERIOR
Os estudos entre a interação do fluxo de fluido e a deformação do meio poroso têm sido realizados com o objetivo de explicar alguns fenômenos que ocorrem ao longo da produção/injeção de fluidos, e assim obter uma simulação de reservatórios cada vez mais precisa. A solução ideal para o problema é implementar um esquema, onde as leis que governam o fluxo e analise de tensões sejam obedecidas simultaneamente em cada intervalo de tempo. Este trabalho apresenta os resultados de um código (programado em C positivo positivo) que permite acoplar um simulador de fluxo convencional (ECLIPSE) e um programa que permite analisar tensões e deslocamentos (Abaqus /CAE). O objetivo deste trabalho é validar varias soluções para resolver um problema usando os diferentes tipos de acoplamento, que juntamente com uma filosofia empregada nas principais formulações permite dar respostas similares aquelas do acoplamento total. São apresentadas as formas de acoplamento e a formulação empregada em cada um dos esquemas usados. Os resultados obtidos pelos esquemas são comparados em termos de fluxo e tensões e deslocamentos a partir de modelos tridimensionais.
Studies between the interaction of fluid flow and deformation of porous media have been carried out with the aim of explaining some phenomena that occur along the production/injection of fluids, thereby obtaining a more accurate reservoir simulation. The ideal solution for this problem is to implement a scheme where laws governing the flow and stress analysis are met simultaneously at each time interval. This dissertation presents the results of a computer code (programmed in C positive positive) that allows the coupling of a conventional reservoir simulator (ECLIPSE) and a stress-displacement finite element based program (Abaqus /CAE). This work presents the use of various coupling schemes for the solution of a synthetic case, in particular the use of a methodology that generates results very close to the ones predicted from the use of fully coupled methods. The results obtained by the different coupling schemes are compared in terms of fluid pressure, stress and displacement responses for synthetic three-dimensional models.

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Ibrahim, Adam. "Petroleum potentielities of reefal carbonate reservoirs in the Mesopotamian Basin." Bordeaux 3, 2009. http://www.theses.fr/2009BOR30088.

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L’Irak possède des grandes réserves d’hydrocarbures, mais la majorité de ses 78champs du pétrole produisent des pièges de type structural. Ses réserves réelles sont sous estimés, car la grande majorité du pays est insuffisamment exploré, le forage a rarement pénétré au-delà du Crétacé Inferieure. Les réserves dans les ouches profondes ne représente que 1% et le Western Désert, tés attractive du point de vu pétrolier reste inexploré. Cette étude, basée sur des données géophysiques, géologiques et des réservoirs démontre et pour la première fois, l’existence d’une grande concentration des constructions récifales dans le Bassin Mésopotamien dans plus de vingt niveaux stratigraphiques. Ces constructions récifales ont été identifiées sur la base des critères sismiques bien établi. Puis sont comparées avec des réservoirs des facies récifaux dans différent champs du pétrole à travers le monde. Les données géologiques montrent l’existence des conditions structurales, climatiques morphologiques et sédimentaire favorables pour la croissance récifale dans le Bassin Mésopotamien durant la période du Permien au Miocène. Les données pale hydrologiques et tectoniques montrent également l’existence des conditions optimales pour avoir lieu des processus dia génétiques susceptible d’améliorer les propriétés petro physiques des réservoirs récifaux. Les données sédimentaires indiquent l’existence des dépositions des roches mère dans la partie profonde du bassin ainsi que l’existence des roches couverture épaisses et imperméables, formées dans leur grande majorité des évaporites. La migration, commencée au Crétacé Supérieur, a continué durant le Tertiaire et le Quaternaire, ce qui a rendu possible l’existence des réservoirs au Miocène. La zone optimale d’existence des réservoirs récifaux s’étend sur la marge de la Platform Arabique, à l’ouest de l’Euphrate, entre la paleostructure de Mosul dans le nord et la paleostructure de Qatar dans le sud du Plateau Arabique
The Iraq host great reserves of oil and gas but the majority of its 78 fields is producing from reservoirs related to structural type trap. Its real reserves are largely underestimated. The major part of Iraq is still insufficiently explored, the drilling are rarely penetrated deeper than the Lower Cretaceous, the Pre-Cretaceous reservoirs represent just 1% and the Western Desert, very attractive for the exploration of deep strata, is still untouched. This work, based on geophysical, geological and reservoir data demonstrate, for the first time, the existence in the Mesopotamian Basin of important concentration of reefal carbonate traps. These stratigraphic reservoirs are identified in more than twenty stratigraphic levels going from Permian to Miocene. The carbonate buildups were identified on the basis of well established seismic criteria and are successfully compared with reefs in many oil and gas producing reservoirs across the world. The geological data, based on sedimentary, climatic and morphologic criteria, confirm that the carbonate and evaporite constitute the dominant lithology in the Arabian Plate. These sediments are the main associated lithology for carbonate buildups. The structural and paleohydological data confirm the existence of optimum conditions for diagenetic processes leading to enhancement of petrophysical properties of the reefal reservoirs. The sedimentary data confirm the existence of the constructor organism, the optimum conditions for the deposition of mature source rocks in the deeper part of the basin and the existence of thick and impermeable seals with a tardive migration. The delineated optimum reefal setting is the platform margin, situated to the west of the Euphrates and covering the area joining the Mosul Height in the north and the Qatar Height in the south. This area is the site of new potential petroleum prospects in Permian, Upper and Middle Triassic, Lower, Middle and Upper Jurassic, Lower, Middle and Upper Cretaceous and in Paleocene, Eocene and Oligocene. The seismic data, through the delineation of several direct hydrocarbon indicators associated to many of the identified reefal reservoirs, highly indicate their petroleum potentialities

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Calleja, Glecy School of Biological Earth &amp Environmental Sciences UNSW. "Influence of mineralogy on petrophysical properties of petroleum reservoir beds." Awarded by:University of New South Wales. School of Biological, Earth and Environmental Sciences, 2005. http://handle.unsw.edu.au/1959.4/22423.

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Key petrophysical properties of reservoir sequences are determined by their individual mineral compositions, and are routinely evaluated through the analysis of cores and geophysical well logs. However, mineralogical studies are seldom incorporated in reservoir assessment. The objectives of the study were to investigate the influence of mineralogy on petrophysical properties of petroleum reservoir beds and the application of mineralogical studies in reservoir evaluation. Mineralogical analyses were performed on core samples from the Plover Formation, the principal reservoir sequence in the Northwest Shelf area of Australia, intersected in two separate wells in the Laminaria petroleum field. The techniques used included X-ray powder and oriented-aggregate analysis, optical microscopy and whole rock geochemistry. Quantification of each mineral phase based on whole-rock powder data was performed using the Rietveld-based Siroquant technique. Results from the Siroquant assay were used as an indicator of mineralogy for the individual samples and were compared with core plug and geophysical log data. X-ray micro-tomography analysis of selected samples was also performed. The reservoir sequences in both wells were sand-dominated, consisted mostly of quartz, clay mineral matrix and cement of silica, pyrite or calcite. The abundance of clay minerals increased in the shale and shaly sandstone intervals. Comparison of mineralogical and core plug analyses of samples from the same depths showed that the down-hole variations in porosity, permeability, grain density and radioactivity were accompanied by changes in mineralogy. Higher proportion of clay minerals in shales was indicated by higher gamma log signals. The gamma log may be taken as an indicator of shaliness only in intervals where kaolinite is proportional to the quantity of illitic clays. Sonic log and neutron log porosity values are comparable with core plug porosity data in sandstone intervals. However, clay minerals increase the sonic log response, thereby increasing porosity in shaly intervals. Clay minerals tend to decrease the neutron log response causing higher porosity indication in shales, similar to that expected in sandstones. Routine density log analysis underestimated porosity values because of the contribution of dense minerals to the bulk density of the formation. Use of laboratory determined grain and fluid densities resulted in improved density log porosity compared to core porosity. X-ray tomography analysis revealed an overall positive correlation between mineralogy and porosity data. Routine geophysical log evaluation revealed inconsistent results when compared to core analysis data because of the influence of minerals on various logs. It is essential that mineralogical studies be included in reservoir assessment. X-ray tomography may provide an alternative approach in evaluating porosity and mineralogy.

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Rieven, Shirley A. (Shirley Ann) 1962. "Analysis and interpretation of clustered microseismicity at geothermal and petroleum reservoirs." Thesis, Massachusetts Institute of Technology, 1999. http://hdl.handle.net/1721.1/9679.

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Thesis (Ph.D.)--Massachusetts Institute of Technology, Dept. of Earth, Atmospheric, and Planetary Sciences, 1999.
Includes bibliographical references (v. 2, leaves 394-410).
This thesis presents the analysis and interpretation of four microearthquake clusters near geothermal and petroleum reservoirs. One cluster was induced during a controlled hydraulic fracture experiment conducted by Atlantic Richfield Corporation (ARCO). The other three clusters occurred near geothermal fields in western Italy during condensate reinjection. Analysis of events induced during ARCO's Deep Well Treatment and Injection project demonstrated "real-time" hypocenter modeling for hydraulic fracture diagnostics. The injection produced a hydraulic fracture that exhibited strong spatial asymmetry. Analysis of the results suggest that the phenomenon of "screenout" may be one mechanism contributing to the observed seismicity's spatial and temporal characteristics and the direction of the asymmetric failure may be related to heterogeneities in formation depositional structures. A swarm of events in 1993 near the northern boundary of the Larderello Geothermal field occurred just below an important regional seismic reflector known as the "K" horizon. The distribution of events suggests that seismic slip on steeply dipping, northwest-southeast striking Tortonian age normal faults could account for the observations and that high pressure fluids circulating in the fracture zone of the "K" horizon cause stress changes and slip on localized patches of the faults. Due to the relative depth of this swarm, compared to reservoir depths, this cluster was attributed to the natural geodynamics of this complex area. Analysis of a set of events from the LAGO seismogenic zone in the Larderello Geothermal field again showed a spatial association with the seismic "1(11 horizon and a lateral NW-SE linear distribution that correlated well with the direction of regional extension. Finally, this thesis reports the results of the relative event relocation for a 1997 swarm of events from the Monte Amiata geothermal field. The hypocenters are located very near a northwest-southeast striking fault at depths correlated with the deeper of two actively producing fracture zones of the Piancastagnaio field.
by Shirley A. Rieven.
Ph.D.

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Al-Aulaqi, Talal Jamal Mubarik. "Wettability alteration in rock reservoirs and its effect in petroleum recovery." Thesis, University of Leeds, 2012. http://etheses.whiterose.ac.uk/21136/.

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Reservoir wettability is controlled by crude oil/rock/brine interactions. Wettability plays an important role in oil recovery because of its effect on fluid location, flow behaviour and residual oil distribution. In mature oil fields, a development programme is initiated to maintain oil production in economic size. Understanding reservoir wettability is a central issue in such field development plans which can be optimised to boost oil production rate. However, there is a considerable uncertainty in understanding the reservoir wettability especially in terms of effect of brine composition and temperature. This thesis serves to minimise such uncertainty. In the present work, several experimental techniques are employed to investigate crude Oil/brine/rock interaction in mineral surface. A protocol of contact angle measurements is developed to mimic the drainage of oil thorough receding contact angle and imbibition of water through advancing contact angle. Experiments are designed carefully to investigate the role of water film, brine composition, asphaltene content, crude oil solvency and temperature in wettability of mineral surface. The consequence of wettability alteration is studied in how fluid behaviour is developed and affects the trapping fluids. A two dimensional glass micromodel gives new visual insights into the type of flow behaviour as a function of brine salinity and temperatures. Furthermore, the role of capillary number is investigated in three distinctive wettability scenarios that exist in oil fields. Real rock surfaces, which are extracted from underground reservoirs in Oman, are studied extensively to understand the role of mineralogy in rock surface. A novel experimental combination between Nuclear Magnetic Resonance (NMR) and capillary imbibition test are utilised to track the wettability alteration in core samples as brine salinity and temperature manipulated. For the first time, the introduction of optical interferometry to petroleum recovery literature is achieved successfully by using vertical scanning interferometry. A detailed investigation of surface profile of crude oil adsorption gives new information on nanoscale wettability. Application of the above-mentioned techniques to different crude oils on different reservoir conditions allows the establishment of fundamental wettability understanding to current enhance oil recovery techniques such as smart water flooding and steam injection. To our best knowledge, some of these finding are reported for, the first time.

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Fonseca, Rojas Mirla Josefina. "Phase behaviour modelling of water-hydrocarbon in high temperature petroleum reservoirs." Thesis, Heriot-Watt University, 2006. http://hdl.handle.net/10399/2152.

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Development of high pressure-high temperature (RPHT) reservoirs is increasingly being pursued world wide to exploit hydrocarbon from deep formation. Due to their extreme conditions (can be up to 2000e and 16000 psia), composition of RPHT fluids can be considerably different from that of conventional reservoirs, particularly the concentration of heavy hydrocarbons in the vapour phase can be quite high. Also, at high temperature the amount of water dissolved in the reservoir hydrocarbon phase could be significant and should be taken into account in detennining the phase and volumetric properties of the fluids. In this study, a model based on equations of state (BOS) was developed to predict phase behaviour of RPHT fluids in the presence of water. The conventional mixing rule was modified by adding a non-random element in the attractive term of EOS. This modification was required to describe the interaction between non-polar (hydrocarbon) and polar (water) compounds. The developed phase behaviour model with the added term to the conventional mixing rules was evaluated for predicting the phase behaviour of hydrocarbon mixtures in presence of water. The conventional (random) interaction parameters (kij) and the non-random interaction parameter of the asymmetric term (lpi) for water-hydrocarbons were determined by matching the solubility data of hydrocarbon-water binary systems in vapour-liquid equilibrium for light and in liquid-liquid equilibrium for intermediate and heavy hydrocarbons. A method based on the Krichevsky-Kasarnovsky equation was developed to correct the effect of pressure on fugacity of the solute in the liquid phase in liquid-liquid equilibrium. The determined binary interaction parameters (BIP) were generalised by correlating them with critical properties and the molecular weight of hydrocarbons. The reliability of the model was evaluated against measured data, not used in its development, over a wide range of pressure and temperature and compared with those of leading models reported in the literature. The model could reliably predict the presence of free water phase and the effect of pressure on the liquid water phase at high temperatures. It also reliably predicted the effect of water on saturation pressure of tested synthetic reservoir fluids. However, it failed to accurately reproduce the effect of addition of water on the volumetric behaviour of the liquid hydrocarbon phase.

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Cai, Xiao. "An Analytical Method for Predicting Wellbore Temperature Profile During Drilling Gas Hydrates Reservoirs." Thesis, University of Louisiana at Lafayette, 2016. http://pqdtopen.proquest.com/#viewpdf?dispub=10163276.

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Production of natural gas from unconventional gas-hydrate reservoirs faces kinds of challenges and uncertainties. One of the main and most common problems in gas-hydrates drilling is the dissociated gas from gas hydrates with decrease of pressure, increase of temperature, or combination of them. A reliable method that can be applied to predict the temperature profile of fluid during circulating in the drilling pipe and the annulus is needed. An analytical model was developed in this study for predicting temperature profiles in drilling gas-hydrate deposits. A case study is provided and indicates a good consistency between model-implications and field observations. According to the sensitivity analyses, the temperature profile of fluid in the drill pipe can be affected by the thickness of drill pipe, density and heat capacity of drill mud, pumping rate of drill mud, geo-thermal gradient, and the surface geo-temperature. The bottom hole temperature is dominated by the temperature and flow rate of the injected drilling fluid, thermal conductivity of cement, heat capacity and density of drill mud, geo-thermal gradient and geothermal temperature at surface, thickness of drill pipe, and cement sheath. Higher geothermal gradient and surface geothermal temperature can lead to a higher temperature profile of fluid in the annulus. The Joule-Thomason cooling effect below the drill bit nozzles will rapidly diminish in a short interval above the bottom hole by the heating effect of geo-thermal gradient. The rate of penetration of drill bit has negligible effect on the fluid temperature profile due to the low percentage of heat flow contributed by the drill cuttings.

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19

Del, Castillo Maravi Yanil. "New inflow performance relationships for gas condensate reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969/354.

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Firincioglu, Tuba. "Bubble point suppression in unconventional liquids rich reservoirs and its impact on oil production." Thesis, Colorado School of Mines, 2013. http://pqdtopen.proquest.com/#viewpdf?dispub=3558341.

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The average pore size in producing unconventional, liquids-rich reservoirs is estimated to be less than 100 nm. At this nano-pore scale, capillary and surface disjoining force interactions, such as van der Waals, structural, and adsorption, affect the phase behavior that is not considered to be significantly, different than in conventional reservoirs. In this dissertation, a comprehensive discussion of the thermodynamics required to model phase behavior of unconventional, liquids-rich reservoirs is presented. Three oil compositions from different unconventional reservoirs are used to generate results.

The impact of confinement manifests itself in the form of reduction of the liquid pressure at which the first gas bubble forms when compared to the bulk fluid measurements in PVT cells. It is shown that the suppression of the bubble-point pressure impacts the saturated portion of the liquid formation volume factor and extends the undersaturated portion of the curve. The equilibrium gas composition is different for each supersaturation level and the gas is composed of lighter components as the supersaturation, i.e., the bubble-point suppression, increases. The minimum radius of the pore that is required to form a specified size bubble is also investigated and the range of pore sizes required under different assumptions is reported.

The impact of this phase behavior deviation on the flow of confined fluids is investigated using a black-oil simulator, COZSim, which evaluates gas and oil fluid properties at corresponding phase pressures. The simulator was independently developed in a DOE project with the capability to incorporate the findings of this research. The results of the analysis show that there is a difference in gas production and gas saturation distribution in the reservoir with and without the confinement impact on the PVT properties. The produced GOR is lower when the confinement is considered due to the bubble-point suppression. These results indicate that the use of bulk fluid measurements in modeling and predicting the performances of nano-porous unconventional reservoirs may result in significant underestimation of the reservoir potential.

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21

Al-Gheithy, Ali Amor. "Modelling of transient flow and pressure behaviour in multilayer stratified reservoirs." Thesis, Imperial College London, 1993. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.261209.

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22

Okon, Anietie Ndarake. "WATER CONING IN FRACTURED RESERVOIRS: A SIMULATION STUDY." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19598.

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Water coning is a complex phenomenon that depends on a large number of variables which include among others: production rate, perforation interval, mobility ratio, capillary pressure, etc. Its production can greatly affect the productivity of a well and the reservoir at large. In fractured reservoirs, the phenomenon is more complex owing to the high permeability of the fractures in the porous media. With this complexity in mind, water coning behaviour in fractured reservoir was studied by simulating a reservoir supported by a strong aquifer using ECLIPSE-100 Black-Oil Simulator. The water cut (WCT), oil production rate (OPR) and water saturation (BWSAT) at the producing interval (Block 1, 1, 7) were used to evaluate the coning phenomenon in a fractured reservoir. In the course of the study, sensitivity analyses on the modelled reservoir’s anisotropy ratio (kv/kh), production rate (q), storativity capacity (ω), fracture width (b) and fracture permeability (kf) were conducted to evaluate their effect on coning behaviour in fractured reservoir. The results obtained depict that while the anisotropy ratio is very significant in water cut and water saturation at the perforating interval it has no adverse effect on oil production rate. It was however, observed that the water cut and oil production rate decreased as the production rate (q) increased. Furthermore, the water cut, oil production rate and water saturation (BWSAT) from the fractured reservoir is sensitive to the storativity capacity (ω) depending on the fracture porosity (φf). Conversely, the fracture’s width (b) and permeability (kf) have no significant effect on the coning behaviour of the modelled fracture reservoir. However, anisotropy ratio (kv/kh), production rate as well as storativity capacity (ω) are significant parameters in evaluating coning phenomenon in fractured reservoirs.

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23

Tandon, Rohit 1966. "Effect of matrix shrinkage on permeability of coalbed methane reservoirs." Thesis, The University of Arizona, 1991. http://hdl.handle.net/10150/278042.

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The dynamic nature of coalbed methane reservoir permeability makes the continuous modeling of the flow process difficult. Knowledge of conventional reservoir modeling is of little value because the gas storage and flow mechanisms in coal are remarkably different. Field observations suggest that the gas productivity does not decline with time as expected. An increasing permeability is a possible explanation. This laboratory study is aimed at measuring the volumetric changes in coal matrix resulting from gas desorption, its impact on coal porosity and permeability, and an estimate of the stage when the effect is significant. Results using cylindrical samples of coal suggest that coal matrix shrinks with desorption of gas. The shrinkage is linearly proportional to the quantity of gas desorbed. Using the measured changes in matrix volume, variations in total and cleat porosity were estimated and found to increase significantly with desorption. These changes should, therefore, be used as input when simulating long-term gas production.

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24

Lei, Guowen. "Producing Gas-Oil Ratio Performance of Conventional and Unconventional Reservoirs." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19514.

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This study presents a detailed analysis of producing gas-oil ratio performance characteristics from conventional reservoir to unconventional reservoir. Numerical simulations of various reservoir fluid systems are included for comparison. In a wide sense of the word, the term of unconventional reservoir is including tight gas sand, coal bed methane, gas hydrate deposits, heavy oil gas shale and etc. In this study we specify the unconventional reservoir to only mean the low and ultra low permeability reservoir, which is including tight or shale reservoir. As an emerging research topic in the E&P industry, shale reservoir’s long-term well performance characteristics are generally not well understood (Anderson et al. 2010). Research methods and techniques for conventional reservoir are usually directly used in this unconventional reservoir analysis. These methods, however, have proven to be too pessimistic (Anderson et al., 2010). Fit-for-purpose approaches or solutions should be introduced in this new topic. Recently, hydraulic fracturing treatment is commonly used in the low matrix permeability reservoir to attain an economic production rate. The difference of well production performance between conventional reservoir and unconventional reservoir is not well known. In this study, we are trying to give a quantitative analysis in order to answer this question.In this study, a “generic” reservoir from field data with constant reserves and size were assumed. This reservoir model is homogeneous and of constant porosity, permeability and initial water saturation. In order to compare the production performance, fluid systems are varied from volatile oil to near critical oil, to gas condensate and to wet gas. The permeability of the reservoir model is also designed from high (conventional reservoir) to ultra low (unconventional), which ranges from 101 to 10-5 mD. Influence from fracture is especially considered because fractures in the low permeability reservoir provide a high conductivity that connects the reservoir matrix to the horizontal well. Fractures in the model are designed with identical geometrical characteristics (length, thickness) and of inner homogeneous properties (porosity, permeability).A black-oil model is used for each reservoir, and its PVT properties are generated with a 31 components EOS model using Whitson-Torp procedure (Whitson et al., 1983). Reservoir fluid systems equilibrium calculation in the black-oil model is done using the initial gas-oil ratio. We have compared the well’s production performance for each fluid system.Based on the industry experience, two standards are used in reservoir simulation control: gas production rate and cumulative revenue. The gas production rate with 10 ×106 ft3/day in the first 10 days or the cumulative revenue equal to 5 ×105 USD from the first 10 days is set as the standard for the commercial well rate. All of these simulations are run under the control of these two types which have just been mentioned. A case of liquid rich gas reservoir is analyzed systematically, to compare its production performance when reservoir permeability is changed from high to low. We are interested in how much oil or gas condensate can be extracted from the “reservoir” if same initial fluids in the reservoir but of a different permeability. This study is useful and practical, particularly for the industry in the era of “high” oil price and “low” gas price in North America.The simulation results show that we can extract more liquid from the reservoir if the matrix permeability is higher, particularly for the reservoir with initially large oil contents (volatile oil reservoir, near critical reservoir and gas condensate reservoir). Fracturing treatment in unconventional reservoir is required to attain an economic production rate. We also realize that for the required number of fractures and reservoir’s matrix permeability, there exists linear correlation in log-log plot in the low-permeability reservoir. In this study, the unique optimization software Pipe-It and reservoir simulator SENSOR are used. Optimal simulation results of permeability combination are obtained by the module Optimizer in Pipe-It.

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Hajizadeh, Yasin. "Population-based algorithms for improved history matching and uncertainty quantification of petroleum reservoirs." Thesis, Heriot-Watt University, 2011. http://hdl.handle.net/10399/2423.

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In modern field management practices, there are two important steps that shed light on a multimillion dollar investment. The first step is history matching where the simulation model is calibrated to reproduce the historical observations from the field. In this inverse problem, different geological and petrophysical properties may provide equally good history matches. Such diverse models are likely to show different production behaviors in future. This ties the history matching with the second step, uncertainty quantification of predictions. Multiple history matched models are essential for a realistic uncertainty estimate of the future field behavior. These two steps facilitate decision making and have a direct impact on technical and financial performance of oil and gas companies. Population-based optimization algorithms have been recently enjoyed growing popularity for solving engineering problems. Population-based systems work with a group of individuals that cooperate and communicate to accomplish a task that is normally beyond the capabilities of each individual. These individuals are deployed with the aim to solve the problem with maximum efficiency. This thesis introduces the application of two novel population-based algorithms for history matching and uncertainty quantification of petroleum reservoir models. Ant colony optimization and differential evolution algorithms are used to search the space of parameters to find multiple history matched models and, using a Bayesian framework, the posterior probability of the models are evaluated for prediction of reservoir performance. It is demonstrated that by bringing latest developments in computer science such as ant colony, differential evolution and multiobjective optimization, we can improve the history matching and uncertainty quantification frameworks. This thesis provides insights into performance of these algorithms in history matching and prediction and develops an understanding of their tuning parameters. The research also brings a comparative study of these methods with a benchmark technique called Neighbourhood Algorithms. This comparison reveals the superiority of the proposed methodologies in various areas such as computational efficiency and match quality.

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Wang, Yilin. "Simulation of fracture fluid cleanup and its effect on long-term recovery in tight gas reservoirs." [College Station, Tex. : Texas A&M University, 2008. http://hdl.handle.net/1969.1/ETD-TAMU-3222.

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27

Makhlouf, Eliana Mary Seinfeld John H. Seinfeld John H. "Estimation of absolute permeability in multilayered petroleum reservoirs with two- and three-phase flow /." Diss., Pasadena, Calif. : California Institute of Technology, 1990. http://resolver.caltech.edu/CaltechETD:etd-03162007-091347.

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28

RIGHETTO, GUILHERME LIMA. "HYDROMECHANICAL SIMULATION OF FAULT REACTIVATION IN PETROLEUM RESERVOIRS: APPROACHES BY CONTACT INTERACTIONS AND PLASTICITY." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2012. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=20410@1.

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PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO
CONSELHO NACIONAL DE DESENVOLVIMENTO CIENTÍFICO E TECNOLÓGICO
Visando aumentar a produção de hidrocarbonetos, a indústria do petróleo desenvolveu métodos de recuperação cujo objetivo é obter uma maior produção. Assim, diversos problemas podem ser encontrados quando se faz uso destas técnicas, principalmente a convencional, em reservatórios geologicamente complexos. Por outro lado, a consideração de estruturas geológicas na engenharia de reservatórios, como as falhas, tem caráter fundamental para a determinação de respostas realísticas quanto à produção de hidrocarboneto. No caso específico da falha, a sua consideração no modelo apresenta importância significativa no âmbito atual, principalmente no que diz respeito à possibilidade de reativação, relacionada com o surgimento de um caminho preferencial para o hidrocarboneto, implicando, nos casos mais críticos, no escape de fluido e na possível perda da estanqueidade do reservatório. Neste contexto, foram idealizados quatro modelos de reservatório com inclinações de falha e zona de falha de 80 graus e 60 graus. Aliado às simulações hidromecânicas, foram estudadas duas abordagens numéricas para tratar o plano/zona de falha. A primeira metodologia empregada faz uso de interações de contato e a falha foi tratada como um plano. A segunda metodologia considera uma zona de falha cujo comportamento é dado pelo critério de plastificação de Mohr-Coulomb. Pela análise dos resultados foi observado que o emprego de interações de contato requer a utilização de um modelo de atrito que leve em consideração a queda das tensões normais efetivas no critério de ruptura. O modelo de plasticidade apresentou resultados consistentes em relação ao processo de reativação da zona de falha para os modelos construídos. Como conclusão geral do trabalho, afirma-se que a consideração de planos de falha ou zonas de falha em reservatórios devem ser definidas cautelosamente no modelo geomorfológico, uma vez que a modelagem destes tipos de estruturas geológicas requer a utilização de diferentes técnicas numéricas para determinar seu comportamento hidromecânico.
Aiming to increase hydrocarbon production, the oil industry has developed recovery methods whose purpose is to get more production. Thus, several problems may be encountered when making use of these techniques, mainly the conventional, in geologically complex reservoirs. In addition, consideration of geological structures in reservoir engineering, such as faults, has fundamental character for determining realistic response for the production of hydrocarbons. In the specific case of faults, its consideration in the model has significant importance currently, especially with regard to the possibility of reactivation associated with the emergence of a preferential path for the hydrocarbon, implying, in the most critical cases, in the leakage of fluid and possible loss of tightness of the reservoir. In this context, four reservoir models were developed with slope of 80 degrees and 60 degrees for the cases of fault plane and fault zone. Using coupled hydro-mechanical simulations we studied two numerical approaches to treat the plan/fault zone. The first methodology makes use of contact interactions and the fault was treated as a plan. The second methodology considers a fault zone whose behavior is given by the criterion of Mohr-Coulomb yielding. In the analysis of the results was observed that the use of contact interactions requires the use of a friction model that takes into account the drop of the effective normal stress in the failure criterion. The plasticity model showed consistent results in relation to the process of reactivation of the fault zone for the models built. As a general conclusion of the study, it is stated that the consideration of fault planes or fault zones in reservoirs must be carefully defined in the geomorphological model, since the modeling of these types of geological structures requires the use of different numerical techniques to determine their hydromechanical behavior.

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29

Li, Youjun. "Bayesian Non-Linear Quantile Regression with Application in Decline Curve Analysis for Petroleum Reservoirs." Case Western Reserve University School of Graduate Studies / OhioLINK, 2017. http://rave.ohiolink.edu/etdc/view?acc_num=case1491607854874719.

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30

Corbett, Patrick W. M. "Petroleum geoengineering : the systematic measurement, interpretation and modelling of geological media for engineering the subsurface for the optimum exploitation of petroleum reservoirs." Thesis, Heriot-Watt University, 2005. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.434937.

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31

Yusuf, Nurudeen. "Modeling well performance in compartmentalized gas reservoirs." [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-2107.

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32

Tingas, John. "Numerical simulation of air injection processes in high pressure light & medium oil reservoirs." Thesis, University of Bath, 2000. https://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.343763.

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Research, pilot scale and field developments of In-Situ Combustion (ISC) for enhanced oil recovery (EOR) in shallow, low pressure, heavy oil reservoirs intensified between the first and the second oil crisis from 1973 to 1981. A decline of interest in EOR followed the collapse of the oil prices in 1986. Renewed interest on in-situ combustion EOR research in the late 1980’s and beginning of the 1990’s was expanded and focused on high pressure medium and light oil reservoirs. The applicability of air injection in deep high pressure light petroleum reservoirs was established by research work of Greaves et al. in 1987 & 1988, Yannimaras et al. in 1991 and Ramey et a l in 1992. Accelerating rate calorimeter (ARC) tests were used to screen the applicability of various types of light oil reservoirs for in-situ combustion EOR by Yannimaras and Tiffin in 1994. The most successful light oil air injection project in the 1990s in the Medicine Pole Hills Unit, Williston Basin, N. Dakota started in 1987 and was reported by Kumar, Fassihi & Yannimaras, in 1994. Low temperature oxidation of light North Sea petroleum was studied at the University of Bath. A high-pressure combustion tube laboratory system was built at Bath University to evaluate performance of medium and light petroleum in-situ combustion processes. Gravity effects and the impact of horizontal wells in Forced Flow In-Situ Combustion Drainage Assisted by Gravity (FFISCDAG) were studied with three-dimensional combustion experiments. In this study, the university of Bath combustion tube experiments have been simulated and history matched. The tube experiments were up-scaled and field simulation studies were performed. A generic PVT characterization scheme based on 5 hydrocarbon pseudo-components was used, which was validated for light Australian and medium ‘Clair’ oil. A generic chemical reaction characterization scheme was used, which was validated for light Australian and medium ‘Clair’ oil. Advanced PVT and chemical reaction characterizations have been recommended for future work with more powerful hardware platforms. Extensive front track and flame extinction studies were performed to evaluate the performance of currently available non-iso-thermal simulators and to appraise their necessity in air injection processes. Comparative ISC field scale numerical simulation studies of Clair medium oil and light Australian petroleum were based on up-scaled combustion tube experimental results. These studies showed higher than expected hydrocarbon recovery in alternative EOR processes for both pre and post water flood implementation of ISC. Further in this study field scale numerical simulation studies revealed high incremental hydrocarbon recovery was possible by gravity assisted forced flow. The applicability of light oil ISC to gas condensate and sour petroleum reservoirs has been examined in this study with promising results. Light petroleum ISC implemented by a modified water flood including oxidants such as H2O2 and NH4NO3 are expected to widen the applicability of ISC processes in medium and light petroleum reservoirs, especially water flooded North Sea reservoirs.

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33

Hattingh, Shane Kenneth Francis. "The simulation of single phase, compressible fluid flow in fractured petroleum reservoirs using finite elements." Doctoral thesis, University of Cape Town, 2002. http://hdl.handle.net/11427/4888.

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Summary in English.
Bibliography: leaves 181-193.
In this thesis, commonly used equations governing the flow of fluids are reviewed, from first principles where appropriate. The assumptions that are made in the process are critically assessed and their limitations are discussed. The equations deal with flow through a porous and permeable medium, a single fracture, a network of fractures, and with the coupling of the fracture network and blocks of matrix material.

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34

Nfor, Nformi Emmanuel. "Sequence stratigraphic characterisation of petroleum reservoirs in Block 11b/12b of the Southern Outeniqua Basin." University of the Western Cape, 2011. http://hdl.handle.net/11394/2924.

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Magister Scientiae - MSc
The main purpose of this study was to identify and characterize the various sand prone depositional facies in the deepwater Southern Outeniqua Basin which generally tend to form during lowstand (marine regression) conditions producing progradational facies. It made use of sequence stratigraphy and turbidite facies models to predict the probable location of deepwater reservoirs in the undrilled Southern Outeniqua Basin using data from basin margin Pletmos Basin and the deepwater Southern Outeniqua Basin. Basin margin depositional packages were correlated in time and space with deepwater packages. It was an attempt at bridging the gap between process-related studies of sedimentary rocks and the more traditional economic geology f commercial deposits of petroleum using prevailing state-of-the-art in basin analysis. It enabled the most realistic reconstructions of genetic stratigraphy and offered the greatest application in exploration. Sequence stratigraphic analysis and interpretation of seismics, well logs, cores and biostratigraphic data was carried out providing a chronostratigraphic framework of the study area within which seismic facies analysis done. Nine (9) seismic lines that span the shallow/basin margin Pletmos basin into the undrilled deepwater Southern Outeniqua basin were analysed and interpreted and the relevant seismic geometries were captured. Four (4) turbidite depositional elements were identified from the seismic lines: channel, overbank deposits, haotic deposits and basin plain (basin floor fan) deposits. These were identified from the relevant seismic geometries (geometric attributes) observed on the 2D seismic lines. Thinning attributes, unconformity attributes and seismic facies attributes were observed from the seismic lines. This was preceded by basic structural analyses and interpretation of the seismic lines. according to the structural analysis and interpretation, deposition trended NW-SE and NNW-SSE as we go deepwater into the Southern Outeniqua basin. Well logs from six (6) of the interpreted wells indicated depositional channel fill as well as basin floor fans. This was identified in well Ga-V1 and Ga-S1 respectively. A bell and crescent shape gamma ray log signature was observed in well Ga-V1 indicating a fining up sequence as the channel was abandoned while an isolated massive mound-shape gamma ray log signature was observed in Ga-S1 indicating basin plain well-sorted sands. Core analyses and interpretation from two southern-most wells revealed three (3) facies which were derived based on Walker‘s 1978, turbidite facies. The observed facies were: sandstone, sand/shale and shale facies. Sequence stratigraphic characterisation of petroleum reservoirs in block 11b/12b of the Southern Outeniqua Basin. Cores of well Ga-V1 displayed fine-grained alternations of thin sandstone beds and shales belonging to the thin-bedded turbidite facies. This is typical of levees of the upper fan channel but could easily be confused with similar facies on the basin plain. According to Walker, 1978 such facies form under conditions of active fan progradation. Ga-S1 cores displayed not only classic turbidite facies where there was alternating sand and shale sections but showed thick uninterrupted sections of clean sands. This is typical of basin plain deposits. Only one well had biostratigraphic data though being very limited in content. This data revealed particular depth sections and stratigraphic sections as having medium to fast depositional rates. Such rates are characteristic of turbidite deposition from turbidity currents. This study as well as a complementary study by Carvajal et al., 2009 revealed that the Southern Outeniqua basin is a sand-prone basin with many progradational sequences in which tectonics and sediment supply rate have been significant factors (amongst others such as sea level change) in the formation of these deepwater sequences. In conclusion, the Southern Outeniqua basin was hereby seen as having a viable and unexplored petroleum system existing in this sand prone untested world class.
South Africa

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Deshpande, Vaibhav Prakashrao. "General screening criteria for shale gas reservoirs and production data analysis of Barnett shale." [College Station, Tex. : Texas A&M University, 2008. http://hdl.handle.net/1969.1/ETD-TAMU-2357.

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36

Scheibe, Christian. "The application of whole-rock geochemistry and mineral chemistry to the correlation of mesozoic reservoirs within the Alwyn area, N. North Sea." Thesis, University of Aberdeen, 2002. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=88108.

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Mesozoic reservoirs in the Alwyn Area, N. North Sea, contain ephemeral/perennial fluvial depositions and associated flood plain fines deposited in a semi-arid environment. Such successions are typically barren of fauna and monotonous in respect to t heir lithologies, which results in non-diagnostic wire-line log signatures. This study proves the application of whole-rock geochemistry and mineral chemistry as an additional correction tool for such successions in 13 wells in the Alwyn Area. The geological and sedimentological environments and conditions were established from sedimentological reports provide by TotalFinaElf Exploration UK (TFE) and from core studies undertaken during this study. Thirty-nine thin sections were analysed to investigate the mineral abundance in order to identify probable host minerals of the analysed chemical elements (ICP database provided by TFE and 202 XRF analyses in this study). Distinguishing between autochthonous and allochthonous mineral content enables one to establish the processes that have modified the entire mineralogical and geochemical composition of the source rock. The chemical elements themselves have been considered with particular regard to their mobility in aqueous fluids. It has been demonstrated that some of the immobile elements in this study are associated with particular heavy minerals. Some elements (though not attributed to particular minerals) show significant, correlatable geochemical signatures. The whole-rock geochemistry and the mineral chemistry of certain heavy minerals are used for provenance studies and chemostratigraphic correlation approaches. In combination with Sm-Nd provenance ages from other studies and available data from literature possible provenances are identified. Ratios between immobile elements are presented as down-hole logs. Twenty-five chemostratigraphic units are established on which basis 13 of 14 wells could be correlated in field wide correlation schemes.

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Passarella, Camila Andrade. "Integração de dados de poços e métodos geoestatísticos para a modelagem geológica do Campo de Namorado." [s.n.], 2012. http://repositorio.unicamp.br/jspui/handle/REPOSIP/263080.

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Orientador: Alexandre Campane Vidal
Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
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Resumo: O presente trabalho foi direcionado para a caracterização e modelagem geológica do reservatório turbidítico do Campo de Namorado. Visto que os depósitos de hidrocarbonetos formaram-se a partir de processos sedimentares e tectônicos complexos que atuaram durante milhões de anos nas bacias e que as informações obtidas destes depósitos são bastante restritas, tornou-se consensual a idéia de que a integração de metodologias e ferramentas possibilita a melhor compreensão dos reservatórios e de suas heterogeneidades. Neste trabalho optou-se por integrar os dados oriundos da geofísica de perfis de poços e dos testemunhos, através dos métodos geoestatísticos de modelagem estocástica com o intuito de gerar modelos equiprováveis do Campo de Namorado que auxiliarão no entendimento da distribuição das principais unidades do reservatório que influenciam na estimativa do volume de óleo. A análise faciológica teve como enfoque os métodos qualitativo, apoiado na descrição das 29 litofácies descritas nos testemunhos, e quantitativo, baseado nas análises dos perfis geofísicos de 54 poços. Com base nesta correlação rocha-perfil, as fácies arenito, arenito argiloso, carbonato e folhelho foram definidos como sendo os prováveis litotipos presentes no reservatório. Para a modelagem geológica e estrutural do Campo de Namorado todos os dados disponíveis foram tratados com o auxílio de um software de modelagem de reservatórios. As etapas de trabalho foram: delimitação de topo e base dos 54 poços do reservatório; interpretação dos três ciclos deposicionais; identificação das falhas; e, por fim, geração de um grid 3D que servirá como base para a realização das modelagens estocásticas subseqüentes. Com a aplicação do método estocástico de simulação seqüencial de indicatriz, foi definida a distribuição espacial das fácies. As propriedades de porosidade efetiva e saturação de água, relacionadas a cada litotipo, foram modeladas a partir da técnica de simulação gaussiana seqüencial. A definição destes parâmetros possibilitou a obtenção do volume de óleo in situ do Campo de Namorado. Como resultados finais foram obtidos vários modelos equiprováveis que representam toda a estrutura do reservatório e possibilitam a quantificação da incerteza associada à estimativa do volume de óleo
Abstract: This work focused the geologic characterization and modeling of the Namorado Oil Field. Sedimentary and tectonic complex processes formed the hydrocarbon deposits for millions of years in the basins, but the information obtained from these deposits is very narrow. In this matter, the opportunity to study the integration of methodologies and tools enables a better understanding of the reservoirs and their heterogeneity. This work integrates the data derived from well logs and cores by the geostatistical methods of stochastic modeling to generate equiprobable models of the Namorado Oil Field, which will assist in the understanding of the distribution of the main reservoir units that influence in the oil volume estimation. The faces analysis used the qualitative method, based on the description of 29 lithofacies described in the cores, and the quantitative method, supported by the well log analysis of 54 wells. Based on this correlation between logs and rocks, was defined as probable reservoir litotypes the faces sandstone, shaly sandstone, carbonate and shale. For the geologic and structural modeling of the Namorado Oil Field all the available data were processed with the aid of a reservoir modeling software. The steps of the work were: delimitation of the top and bottom of the 54 reservoir wells; the interpretation of the three depositional cycles; the identification of failures; and, finally, the generation of a 3D grid for the base of the stochastic modeling. The application of the stochastic method of sequential indicator simulation defined the spatial distribution of the faces. In the other hand, the properties of effective porosity and water saturation related to each lithotype were modeled using the technique of sequential Gaussian simulation. The definition of these parameters allowed the oil volume estimation of the Namorado Oil Field. As a final result, several equiprobable models were obtained representing the entire structure of the reservoir and allowing the uncertainty quantification associated with oil volume computation
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo

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Toelle, Brian E. "Use of 3D Seismic Azimuthal Iso-Frequency Volumes for the Detection and Characterization of High Porosity/Permeability Zones in Carbonate Reservoirs." Thesis, West Virginia University, 2013. http://pqdtopen.proquest.com/#viewpdf?dispub=3538201.

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Among the most important properties controlling the production from conventional oil and gas reservoirs is the distribution of porosity and permeability within the producing geologic formation. The geometry of the pore space within these reservoirs, and the permeability associated with this pore space geometry, impacts not only where production can occur and at what flow rates but can also have significant influence on many other rock properties. Zones of high matrix porosity can result in an isotropic response for certain reservoir properties whereas aligned porosity/permeability, such as open, natural fracture trends, have been shown to result in reservoirs being anisotropic in many properties.

The ability to identify zones within a subsurface reservoir where porosity/permeability is significantly higher and to characterize them according to their geometries would be of great significance when planning where new boreholes, particularly horizontal boreholes, should be drilled. The detection and characterization of these high porosity/permeability zones using their isotropic and anisotropic responses may be possible through the analysis of azimuthal (also referred to as azimuth-limited) 3D seismic volumes.

During this study the porosity/permeability systems of a carbonate, pinnacle reef within the northern Michigan Basin undergoing enhanced oil recovery were investigated using selected seismic attributes extracted from azimuthal 3D seismic volumes. Based on the response of these seismic attributes an interpretation of the geometry of the porosity/permeability system within the reef was made. This interpretation was supported by well data that had been obtained during the primary production phase of the field. Additionally, 4D seismic data, obtained as part of the CO₂ based EOR project, supported reservoir simulation results that were based on the porosity/permeability interpretation.

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Kim, Tae Hyung. "Fracture characterization and estimation of fracture porosity of naturally fractured reservoirs with no matrix porosity using stochastic fractal models." [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-2570.

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Wang, Cong. "A Multi-Scale, Multi-Continuum and Multi-Physics Model to Simulate Coupled Fluid Flow and Geomechanics in Shale Gas Reservoirs." Thesis, Colorado School of Mines, 2018. http://pqdtopen.proquest.com/#viewpdf?dispub=10684514.

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In this study, several efficient and accurate mathematical models and numerical solutions to unconventional reservoir development problems are developed. The first is the three-dimensional embedded discrete fracture method (3D-EDFM), which is able to simulate fluid flow with multiple 3D hydraulic fractures with arbitrary strike and dip angles, shapes, curvatures, conductivities and connections. The second is a multi-porosity and multi-physics fluid flow model, which can capture gas flow behaviors in shales, which is complicated by highly heterogeneous and hierarchical rock structures (ranging from organic nanopores, inorganic nanopores, less permeable micro-fractures, more permeable macro-fractures to hydraulic fractures). The third is an iterative numerical approach combining the extended finite element method (X-FEM) and the embedded discrete fracture method (EDFM), which is developed for simulating the fluid-driven fracture propagation process in porous media.

Physical explanations and mathematical equations behind these mathematical models and numerical approaches are described in detail. Their advantages over alternative numerical methods are discussed. These numerical methods are incorporated into an in-house program. A series of synthetic but realistic cases are simulated. Simulated results reveal physical understandings qualitatively and match with available analytical solutions quantitatively. These novel mathematical models and computational solutions provide numerical approaches to understand complicated physical phenomena in developing unconventional reservoirs, thus they help in the better management of unconventional reservoirs.

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Machado, André Francisco. "Análise quantitativa de mapas de pressão e saturação no processo de ajuste de histórico." [s.n.], 2010. http://repositorio.unicamp.br/jspui/handle/REPOSIP/263752.

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Orientador: Denis José Schiozer
Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
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Resumo: A técnica de ajuste de histórico consiste em modificar o modelo de simulação de modo que este reproduza o histórico de produções e pressões observadas. No entanto, a aplicação dessa técnica nos primeiros anos de produção de um campo fica bastante limitada, principalmente, devido à reduzida quantidade de informações disponíveis. Atualmente, a ferramenta que tem ajudado a minimizar o problema da escassez de informações é a sísmica 4D. Alguns trabalhos recentes têm contribuído para o desenvolvimento de metodologias que integrem informações sísmicas ao processo de ajuste de maneira quantitativa, resultando em modelos ajustados mais confiáveis. O objetivo principal deste trabalho foi continuar com os estudos realizados por Risso (2007) e Ida (2009) no sentido de avaliar a utilização dos mapas provenientes da sísmica 4D no processo de ajuste de histórico de produção. O foco desta pesquisa consiste na aplicação dos mapas de saturação e pressão de forma simultânea no processo de ajuste durante a fase de parametrização do problema para melhor diagnosticar e determinar as heterogeneidades do reservatório. Foi também avaliada a influência da informação do mapa de pressão na fase de otimização como um parâmetro de ajuste no sentido de melhorar a precisão da função-objetivo. Foram estudados dois modelos durante a pesquisa, um para a validação da metodologia e outro para a aplicação da mesma. A validação da metodologia proposta foi realizada num modelo bidimensional five-spot com duas barreiras geológicas e um canal de alta permeabilidade e a aplicação foi realizada num modelo modificado do Campo de Namorado. Nos dois casos, foram constatados ganhos de qualidade no ajuste de histórico proporcionado pela incorporação quantitativa dos mapas de saturação e de pressão
Abstract: The history matching technique consists in modify the simulation model so that it reproduces the historical production and pressure observed. However, applying this technique in the early years of production of a field is rather limited, mainly due limited amount of information available. Currently, the tool that has helped minimize the problem of scarcity of information is seismic 4D. Some works, such as Risso (2007) and Ida (2009), have contributed to the development of methodologies that integrate seismic data to the history matching process in a quantitative way, promoting adjusted models more reliable. The focus of this research was application of pressure map in the history matching process during the parameterization of the problem in order to supplement the information of saturation map to better determine the heterogeneity of the reservoir. In the background was evaluated the influence of pressure map information during optimization as a parameter in order to improve the accuracy of the objective function. The validation of methodology proposed was done in a simple synthetic model and the application was done in the Namorado Field, modified with one geological fault and one channel with high permeability
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo

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Morton, Kirsty Lorna. "Volume of effective influence in multiple probe formation tests using optimisation of geological models of petroleum reservoirs." Thesis, Heriot-Watt University, 2003. http://hdl.handle.net/10399/392.

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Lamine, Mohamed Sadok. "Multi-dimensional higher resolution methods for flow in porous media." Thesis, Swansea University, 2009. https://cronfa.swan.ac.uk/Record/cronfa42721.

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Currently standard first order single-point upstream weighting methods are employed in reservoir simulation for integrating the essentially hyperbolic system components. These methods introduce both coordinate-line numerical diffusion (even in 1-D) and cross-wind diffusion into the solution that is grid and geometry dependent. These effects are particularly important when steep fronts and shocks are present and for cases where flow is across grid coordinate lines. In this thesis, families of novel edge-based and cell-based truly multidimensional upwind formulations that upwind in the direction of the wave paths in order to minimise crosswind diffusion are presented for hyperbolic conservation laws on structured and unstructured triangular and quadrilateral grids in two dimensions. Higher resolution as well as higher order multidimensional formulations are also developed for general structured and unstructured grids. The schemes are coupled with existing consistent and efficient continuous CVD (MPFA) Darcy flux approximations. They are formulated using an IMPES (Implicit in Pressure Explicit in Saturation) strategy for solving the coupled elliptic (pressure) and hyperbolic (saturation) system of equations governing the multi-phase multi-component flow in porous media. The new methods are compared with single point upstream weighting for two-phase and three-component two-phase flow problems. The tests arc conducted on both structured and unstructured grids and involve full-tensor coefficient velocity fields in homogeneous and heterogeneous domains. The comparisons demonstrate the benefits of multidimensional and higher order multidimensional schemes in terms of improved front resolution together with significant reduction in cross-wind diffusion.

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Al-Hajeri, Mubarak Matlak Mubarak. "A conceptual model of the geochemical evolution of geological fluids in South Kuwait and its impact on heavy oil occurrence in Radhuma and Tayarat Formation carbonate reservoirs." Thesis, University of Aberdeen, 2014. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=215550.

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Benvenutti, Carlos Felipe [UNESP]. "Estudo da porção offshore da bacia do Benin e o seu potencial no armazenamento de hidrocarbonetos, margem equatorial africana." Universidade Estadual Paulista (UNESP), 2012. http://hdl.handle.net/11449/92925.

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A presente pesquisa conta com uma área de estudo de 7.737 km2 na porção ojJshore da Bacia do Benin, localizada na Província do Golfo da Guiné, Margem Equatorial Africana, onde a lâmina da água varia de 100 a mais de 3.200 m, cobrindo basicamente o talude. Dados ísmicos 3D e 2D foram disponibilizados pela Compagnie Béninoise des Hydrocarbures(CBH SARL) para interpretação dos mesmos com o objetivo de caracterizar o arcabouço estrutural e estratigráfico da região, assim como avaliar o potencial do armazenamento de hidrocarboneto. Foi necessário o mapeamento dos horizontes sísmicos, a elaboração de mapas de contorno estrutural, de atributos sísmicos e de isópacas. A Bacia do Benin encontra-se entre as zonas de fratura de Romanche e Chain, correlata à Bacia do Ceará na Margem Equatorial Brasileira. Sua evolução tectono-sedimentar está condicionada à ruptura do Gondwana no Cretáceo Inferior, predominando estruturas da fase rifte relacionadas à distensão e transcorrência, a influência da transpressão é muito significativa no Cretáceo Superior. Destaca-se também uma tectônica gravitacional marcada por falhamentos dos níveis estratigráficos cenozóicos. A coluna sedimentar é representada por uma seção rifte continental limitada pela discordância do Meso-Albiano e outra pós-rifte marinha, do Albiano Superior ao Recente; sendo esta subdividida pela discordância do Oligoceno relacionada a uma queda eustática. A sedimentação está controlada pelo strends NE-SW e ENE-WSW, incluindo os canais submarinos. Os principais altos estruturais desta região já foram perfurados sem sucesso comercial, porém o potencial de acumulação de hidrocarbonetos é promissor, pelo menos dois grandes canais foram identificados no estudo em uma região cuja profundidade do fundo do mar é cerca de 2.200 m. Oportunidades...
The present research has a study area of 7.737 km2 located in the offshore portion of Benin Basin in the Gulf of Guinea Province, African Equatorial Margin. The water depth ranges from 100 to more than 3.200 m, basically covering the slope. The Compagnie Béninoise des Hydrocarbures (CBH SARL) provided 3D and 2D seismic data in order to interpret and characterize the stratigraphic and structural frarnework, as well as to evaluate the petroleum exploration potential. To achieve the desired results, it was performed seismic horizons mapping, elaboration of structural outline, isopach and seismic attribute maps. Benin Basin is limited by Romanche and Chain fracture zones and is correlated to Ceará Basin in Brazilian Equatorial Margin. Its tectono-stratigraphic evolution was conditioned by the Gondwana break-up in the Lower Cretaceous and shows rift structures related to extension trike-slip tectonics. The transpression influence is very significant in the Upper Cretaceous. It is also highlighted a gravitational tectonic marked by normal faults in the Cenozoic level. The sedimentary package is represented by a continental rift section limited by a Mid-Albian unconformity and other marine post-rift sequence from Upper Albian to Recent; the last one can still be divided by the Oligocene unconformity. The sedimentation is controlled by NE-SW and ENE- WSW trends, including submarine channels in the Upper Cretaceous. The main structural traps weredrilled in the study area without commercial success. At least two great channels were identified in a region where the water depth is around 2.200 m. Roll-overs and minor channels opportunities in Paleogene and Neogene should also be considered. The pre-rift sequences of the study area are poorly recognized, the absence of well information in this interval and the low resolution of seismic data... (Complete abstract click electronic access below)

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Mishra, Varun. "A model for matrix acidizing of long horizontal well in carbonate reservoirs." Thesis, [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-1957.

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Gong, Yiwen. "Toward Better Understandings of Unconventional Reservoirs - Rock Mechanical Properties and Hydraulic Fracture Perspectives." The Ohio State University, 2020. http://rave.ohiolink.edu/etdc/view?acc_num=osu1605633687308252.

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Martin, Keithan. "Integrating depositional facies and sequence stratigraphy in characterizing carbonate reservoirs: Mississippian limestone, western Kansas." Thesis, Kansas State University, 2015. http://hdl.handle.net/2097/20478.

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Master of Science
Geology
Matthew W. Totten
The Mississippian-aged St. Louis Limestone of Western Kansas is a carbonate resource play that has been producing oil, gas, and natural gas liquids (NGL) for over 50 years. The Mississippian Limestone is made up of heterogeneous limestones with interbedded layers of porous and non-porous units, abrupt facies changes, and diagenetic alterations. These factors combine to characterize the St. Louis Limestone's internal complexity, which complicates hydrocarbon exploration. This study focuses on improving the understanding of the geometry, distribution, and continuity of depositional facies within Kearny County, Kansas. Petrophysical analysis of a suite of geophysical logs integrated with core provided the basis for establishing facies successions, determining vertical stacking patterns within a sequence stratigraphic framework, and correlating areas of high porosity with a respective facies. The following depositional facies were identified; 1) porous ooid grainstone, 2) highly-cemented ooid grainstone, 3) quartz-carbonate grainstone, 4) peloidal grainstone, 5) micritic mudstone, and the 6) skeletal wackestone/packstone. The porous ooid grainstone is the chief reservoir facies, with log-derived porosity measurements between four and eighteen percent. In areas without available core, depositional facies were predicted and modeled using a neural network analysis tool (Kipling2.xla). Values derived from the evaluated core intervals and their respective geophysical logs served as the framework for the neural network model. This study illustrates the advantages of correlating depositional facies with reservoir quality and correlating those specific facies to geophysical logs, ultimately to create a greater understanding of the reservoir quality and potential within the St. Louis Limestone of western Kansas.

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Hatami, Mohammad. "Multiscale Analysis of Mechanical and Transport Properties in Shale Gas Reservoirs." Ohio University / OhioLINK, 2021. http://rave.ohiolink.edu/etdc/view?acc_num=ohiou1614950615095796.

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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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Dissertations / Theses on the topic 'Petroleum reservoirs'

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