Дисертації з теми "Hydrocarbon basins"
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1
Monson, Bryan J. G. "Aspects of hydrocarbon migration and hydrocarbon-metal interactions in sedimentary basins." Thesis, Queen's University Belfast, 1992. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.333838.
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2
Wang, Weihua. "Studies of sandstone diagenesis in hydrocarbon-prospective basins." Thesis, Queen's University Belfast, 1992. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.333852.
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3
Mohammed, Wolela Ahmed. "Sedimentology, diagenesis and hydrocarbon potential of sandstones in hydrocarbon prospective Mesozoic rift basins (Ethiopia, UK and USA)." Thesis, Queen's University Belfast, 1997. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.394602.
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4
Ward, Nicholas I. P. "Subtle traps in sedimentary basins and their importance to hydrocarbon exploration." Thesis, Cardiff University, 2018. http://orca.cf.ac.uk/113131/.
Повний текст джерелаАнотація:
This thesis uses high-quality 3D seismic data from the Broad Fourteens Basin (Southern North Sea), Espírito Santo Basin (SE Brazil), and Taranaki Basin (New Zealand) to characterise the evolution of geological structures related to differential compaction and subsidence; also known as subtle hydrocarbon traps. Each chapter tackles deformation over a different geological feature, spanning from salt-withdrawal basins, to submarine channel complexes and associated mass-transport deposits. These chapters subsequently discuss the impact the results have on the hydrocarbon industry. Included in these discussions are the importance of subtle traps on carbon capture and storage, local sealing potential, and reservoir distribution. The Broad Fourteens Basin dataset was used to investigate concentric faults associated with salt withdrawal from below Triassic units. Throw-depth and throw-distance plots helped to understand the growth histories of the concentric faults. It was shown that these faults formed as a result of the bending of strata due to differential subsidence during salt withdrawal. Slip tendency analyses assessed the likelihood for faults to reactivate and transmit fluids whenever pore fluid pressure is increased. This approach simulated a typical profile during carbon capture and storage. It was shown that concentric faults will reactivate if pore fluid pressures are increased above 30 MPa at the relevant sub-surface depths, leaking fluids (including stored CO2) past regional seal intervals in the basin. Data from the Espírito Santo Basin were first used to assess the timing and magnitude of differential compaction over a submarine channel complex. Thickness-relief models helped quantify both the variations in thickness in overburden strata. Smaller channels associated with downslope knickpoints were located within the channel complex. Differential compaction over channels produced four-way dip closures, as coarse-grained sediments were deposited at the knickpoint base. These provide adequate structural traps after early burial. The Espírito Santo Basin 3D survey was used in a third chapter to assess how differential compaction affected sediment distribution over a mass-transport deposit. As large remnant and rafted blocks entrained within the MTD were buried, differential compaction produced anticlines over them. This created a rugged seafloor and the topographic highs confined sediment moving downslope, allowing it to pond in discrete depocentres. Results from the data analysis chapters were compared with compaction-related structures documented in the published literature. A novel classification for subtle structural traps associated with differential compaction was produced, separating each feature into one of four types; Type A: folds over tectonic structures >2 km wide; Type B: folds over sedimentary packages, typically elongate, ~500 m to 5 km wide; Type C: folds over topographic features that are 20 m to 2 km wide; Type D: folds over sub-seismic/outcrop features no larger than 20 m. The results of the classification can be used as a first assessment when recognising a compaction-related fold and to rapidly assess its evolution and effectiveness as a subtle hydrocarbon trap.
5
Reynolds, Peter William. "Monogenetic basaltic edifices : their architecture, volcanology and importance in hydrocarbon basins." Thesis, Durham University, 2015. http://etheses.dur.ac.uk/11369/.
Повний текст джерелаАнотація:
Flood basalt provinces host significant hydrocarbon reserves. The provinces are produced during fissure eruptions which construct volcanic edifices atop an erupting dyke. The edifices are important components of volcanic-affected hydrocarbon basins; they provide insights into the underlying structural and magmatic plumbing systems, as well as acting as fluid migration pathways after burial. Furthermore, the edifices host a wealth of volcanological evidence that can be used to derive information relating to eruption dynamics such as eruption column height, mass flux and duration; as well as providing insights into the effects of eruptions on the environment. However, the location of the fissures in many hydrocarbon basins is poorly constrained. Furthermore, few studies have characterised the internal architecture of the edifices produced during fissure eruptions. This thesis uses field, seismic and well data to characterise the architecture of monogenetic basaltic edifices and understand their temporal and spatial evolution. Field studies along a dissected Holocene fissure, Northeast Iceland, reveal that a scoria-agglutinate cone, spatter ramparts and a scoria rampart were constructed during Hawaiian-style lava fountaining. These edifices are analogous to those formed in the 1783 Laki eruption. Data gathered in this study can be used to recognise fissure-derived edifices in other volcanic provinces. I then contrast these dyke-fed edifices with rootless cones; a morphologically similar volcanic edifice produced during explosive interaction between inflating pāhoehoe lava and unconsolidated sediment. This thesis reveals that rootless cones can be distinguished from dyke-fed edifices on the basis of their juvenile clast morphology and clast density. This allows us to better recognise dyke-proximal locations. Lastly, I use exceptional quality 3D seismic and well data to show how a series of submarine monogenetic volcanoes evolved; progressing from a maar-forming stage, to a pillow volcano and tuff-cone-building stage as the confining pressure decreased above the growing edifices. These insights allow us to distinguish volcanic edifices from similar non-volcanic edifices in other seismic data sets, and also indicates that our understanding of submarine volcanism has previously been biased towards recognition of constructional features.
6
Spry, Trent B. "Source potential index (SPI) as a hydrocarbon prospectivity ranking factor in Australian Basins /." Title page, contents and abstract only, 1993. http://web4.library.adelaide.edu.au/theses/09SB/09sbs771.pdf.
Повний текст джерелаАнотація:
Thesis (B. Sc. (Hons.))--University of Adelaide, National Centre for Petroleum Geology and Geophysics, 1994.Volume 2 is loose leaf and contains all the Appendices. Includes bibliographical references.
7
Muia, George. "The ''Turkana Grits'' : Potential Hydrocarbon Reservoirs of the Northern and Central Kenya Basins." Thesis, Rennes 1, 2015. http://www.theses.fr/2015REN1S069/document.
Повний текст джерелаАнотація:
Plus des deux tiers des champs pétroliers mondiaux se trouvent dans deux principaux environnements tectoniques : les marges continentales passives et les rifts continentaux. Dans le bassin de Lockichar dans le rift kenyan, plus de 600 millions de barils d'huile extractible ont été découverts. Les roches réservoirs principales dans ce bassin sont les grès de Lokone qui appartiennent à une famille plus large de grès appelés les ‘Turkana Grits', grès arkosiques en sandwich entre le socle métamorphique et les roches volcaniques du Miocène Moyen. La quantité des hydrocarbures dans les grès réservoirs de Lokone ont ainsi motivé la présente étude des ‘Turkana Grits' pour en préciser les caractéristiques en tant que réservoir potentiel d'hydrocarbures. Trois formations sédimentaires, c'est-à-dire, la Formation Kimwarer, la Formation Kamego et le grès de Loriu, qui n'ont jamais été complètement caractérisées du point de vue chronostratigraphique et sédimentologique ont été étudiées à travers des relevés détaillés. Plus de 170 échantillons ont été récoltés pour déterminer leur contenu en fraction détritique et authigène, les zones principales de cimentation des différents affleurements et, à partir d'une analyse des lithofaciès, les environnements de dépôts. Les échantillons de roches volcaniques et intrusives ont également été caractérisés et utilisés pour des datations avec la méthode 39Ar-40Ar. Trois environnements de dépôt superposés ont été déterminés pour la Formation Kimwarer : un chenal fluviatile distal, un cône d alluvial et une plaine d'inondation. L'étude diagénétique montre des changements de ciments à hématite dominante à la base, calcite dominante dans les zones intermédiaires et retour à l'hématite dominante au sommet de la formation. Les épisodes de cimentation opèrent pendant la diagénèse précoce à tardive, à basse température (<80°C), et en condition de compaction mécanique significative. Un âge minimum des dépôts d'environ 18 Ma (Miocène précoce-Burdigalien) a également été établi pour cette formation. La Formation Kamego évolue d'un environnement fluviatile à celui d'une plaine d'inondation et est principalement cimentée par de l'hématite. De la calcite est présente uniquement dans les premiers 5 m. Une coulée de lave peu épaisse interstratifiée dans les sédiments les plus jeunes de la Formation Kamego a livré un âge minimum des dépôts d'environ 20 Ma pour l'essentiel des sédiments. Le grès de Loriu est une formation principalement composée de dépôts de chenal fluviatile. Les principaux ciments sont la calcite, l'hématite et la kaolinite. Un filon intrusif suggère que l'âge minimum des dépôts est d'environ 18.5 Ma. L'analyse de réservoir finale sur les 'Turkana Grits' montre que la compaction et la cimentation sont les agents dominants de la réduction de porosité, et que les ‘Turkana Grits' sont généralement de médiocre à modérément bonnes unités réservoirs. Les grès de Lokone ont des porosités en sub-surface qui s'échelonnent entre 10 et 20 % et des perméabilités aussi élevées que 3 Darcy (Africa Oil Corporation, 2011). A partir des analyses pétrographiques, la Formation Kimwarer a été classée comme ayant la seconde place en tant que réservoir potentiel d'hydrocarbures avec des porosités aussi élevées que 20 % sur certains segments du log stratigraphique étudié. La Formation Kamego a également un bon potentiel mais n'est pas aussi bien classée à cause de la fraction importante de matériel volcanique qu'elle renferme et de la capacité de ce matériel à s'altérer au cours de la diagénèse. Les porosités sont basses dans les grès de Loriu, en conséquence cette formation n'est classée que cinquième parmi les Turkana Grits, réservoir potentiel d'hydrocarburesOver two thirds of the world’s giant oilfields are found in two principle tectonic regimes; continental passive margins and continental rifts. The preferential formation of hydrocarbons in rifts is attributed to the proximal juxtaposition of high grade, lacustrine source rock units with medium to high grade reservoir rocks - a consequence of both faulting and sedimentation in the resulting accommodation space, which in many cases may locally modify the prevailing climatic conditions. In one of such basins, the Lokichar Basin in the Kenyan Rift, over 600 million barrels of recoverable oil have been discovered. The principle reservoir unit in this basin is the Lokone Sandstone that belongs to a larger family of sandstones called the ‘Turkana Grits’, arkosic sandstones that are sandwiched between metamorphic basement and mid-Miocene volcanics. The hydrocarbon proclivity of the Lokone Sandstones as reservoir units motivated further study of the ‘Turkana Grits’, as potential hydrocarbon reservoirs. In this work, three sedimentary formations, i.e. Kimwarer Formation, Kamego Formation and Loriu Sandstones, which have not been previously fully characterized from chronostratigraphic and sedimentological point of views were studied through detailed logging. Over 170 samples were collected to determine, detrital and authigenic components, the main cementation zones in the different outcrops, and, from lithofacies analysis, the depositional environments. Volcanic and intrusive samples were also characterized and used for 39Ar-40Ar dating. Three superposed depositional environments were determined for the Kimwarer Formation, a distal fluvial channel, an alluvial fan and a floodplain depositional environment. The diagenetic study shows cements change from dominant hematite at the base to calcite within the middle zones and back to hematite towards the top of the Formation. These cementation episodes occur during early and relatively late diagenesis in low temperature conditions (<80 °C), under significant mechanical compaction. A minimum deposition age at ca. 18 Ma (Early Miocene – Burdigalian) has also been set for the Kimwarer Formation. The Kamego Formation evolves from fluvial to floodplain depositional environments and is dominantly cemented by hematite. Calcite cement is only noted in the lowermost 5m. A thin lava flow interbedded with the topmost sediments of the Kamego Formation gave a minimum deposition age of ca. 20 Ma for most of the sediments. The Loriu Sandstone is composed predominantly of fluvial channel deposits. The main cements are calcite, hematite and kaolinite clays. A cross-cutting dyke suggests a minimum deposition age of ca. 18.5Ma. A final reservoir analysis of the Turkana Grits shows that while compaction and cementation are dominant agents of porosity reduction, the Turkana Grits are generally poor to moderately good reservoir units. The Lokone Sanstone has been proven to have sub-surface porosities ranging between 10 - 20% and permeabilities as high as 3 darcies (Africa Oil Corporation, 2011). For petrographic analyses, the Kimwarer Formation has been ranked as having the second best reservoir potential with porosities as high as 20% in some sections of its studied stratigraphy. The Kamego Formation also has good potential but is not as highly ranked owing to the huge component of volcanic material that have a greater propensity to diagenetic alteration. No good porosities were noted for the Loriu Sandstone and hence this formation has been ranked 5th amongst the Turkana Grits
8
Kloss, Olaf. "The relationship of faulting to hydrocarbon accumulations in the Barrow and Exmouth Sub-basins /." Title page, abstract and table of contents only, 1996. http://web4.library.adelaide.edu.au/theses/09S.B/09s.bk66.pdf.
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9
Gillam, Daniel J. "Structural and geomechanical analysis of naturally fractured hydrocarbon provinces of the Bowen and Amadeus Basins: onshore Australia /." Title page, table of contents and abstract only, 2004. http://web4.library.adelaide.edu.au/theses/09PH/09phg4758.pdf.
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10
Spaak, Gemma. "Molecular and isotopic perspectives on Australian petroleum systems: Hydrocarbon fluid correlations and source rock depositional environments in the Canning and Browse basins." Thesis, Curtin University, 2017. http://hdl.handle.net/20.500.11937/69412.
Повний текст джерелаАнотація:
This PhD study provides further insights into the petroleum systems of the Canning and Browse basins, Western Australia. Oil-oil correlations, oil-source correlations and palaeoenvironmental reconstructions of Paleozoic source rock intervals are performed. Non-conventional correlation tools such as quantitative diamondoid analysis and δ13C of individual aromatics were successfully applied for hydrocarbon correlation purposes. This work has implications for the petroleum industry but also provides a further understanding of the evolution of life during the Paleozoic.
11
Mohamed, Abdalla Yagoub. "Basin analysis and hydrocarbon maturation, Unity and Kaikang area, Muglad Basin, Sudan." Thesis, University of Aberdeen, 1996. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.390934.
Повний текст джерелаАнотація:
Basin analysis study has been conducted along a cross section in the Unity-Kaikang area, Muglad Basin, Sudan. The research is based essentially on geological, seismic investigations and basin model approach. The basin model approach included two dimensional gravity modelling, and one dimensional thermal history, maturation and hydrocarbon generation modelling. In addition an investigation of the hydrocarbon migration processes, routes to the known and probable accumulation targets is studied. The basin models were calibrated against data obtained from wells drilled in the area. The seismic investigations indicate a sedimentary thickness ranging from 11 to 7 km averaging 9 km along the area of the cross section. The two dimensional gravity model suggests a mantle uplift of 2.18 km and a β stretching factor of 1.47 with a thin crust of 24 km, corresponding to an extension of 45 km. The burial and thermal model suggests a high subsidence rate accompanied by a slow sedimentation rate during the Neocomian and Aptian times. The present heat flow is ranging between 72 (Kaikang area) to 50 mW/m2 averaging 59 mW/m2 along the cross section of the study area. The paleoheat flow is averaging 57 mW/m2 with peaks of 65 mW/m2 during the Aptian-Senomanian, Paleocene to Eocene times and a last peak of 59 mW/m2 between the Miocene and the present. The maturation and hydrocarbon generation model (LLNL, Sweeny 1990) has been applied to the oil prone source rocks of the Abu Gabra and Sharaf formations. For the purpose of modelling the Abu Gabra Formation has been divided into three layers. In the top layers of the Abu Gabra Formation, the model predicts an average onset of oil generation at 90 Ma and an end at 10 Ma. In the combined source rock section of layer three of the Abu Gabra and the Sharaf Formation the model predicts an average onset of oil generation at 110 and an end at 30 Ma.
12
Alalade, Babatunde. "Hydrocarbon Potential of Late Cretaceous Shales, Chad Basin, NE Nigeria." Thesis, University of Newcastle Upon Tyne, 2006. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.519492.
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13
Zhakiya, Elezhan. "Using machine learning for hydrocarbon prospecting in Reconcavo Basin, Brazil." Thesis, Massachusetts Institute of Technology, 2016. http://hdl.handle.net/1721.1/115039.
Повний текст джерелаАнотація:
Thesis: S.B., Massachusetts Institute of Technology, Department of Earth, Atmospheric, and Planetary Sciences, 2016.Cataloged from PDF version of thesis.
Includes bibliographical references (pages [28]).
Machine Learning techniques are being widely used in Social Sciences to find connections amongst various variables. Machine Learning connects features across different fields that do not seem to have known mathematical relationships with each other. In natural resource prospecting, machine learning can be applied to connect geochemical, geophysical, and geological variables. However, the biggest challenge in machine learning remains obtaining the data to train the ML algorithms. Here, we have applied machine learning on data extracted from maps via image processing. While the overall accuracy of prediction remains as low as 33% at this stage, we see places where the algorithm can be improved and the accuracy increased.
by Elezhan Zhakiya
S.B.
14
Pei, Yangwen. "Thrust fault evolution and hydrocarbon sealing behaviour, Qaidam Basin, China." Thesis, University of Leeds, 2013. http://etheses.whiterose.ac.uk/5831/.
Повний текст джерелаАнотація:
In the past, fault seal analysis has been focused on extensional systems. How-ever, fault behaviour in terms of fault sealing is also critical within compressional thrust systems. The results of an evaluation of thrust fault evolution and hydro-carbon sealing behaviour in the Lenghu5 thrust belt of the Qaidam basin of NW China are reported. A multi-scale methodology, ranging from regional- to micro-scale, is utilized in this work to identify the detailed thrust fault architecture and its effect on hydrocarbon sealing properties. Regional-scale sections and 3D modelling are used to evaluate the evolution of faults within this thrust system and as a platform for detailed seal analysis. The results allow assessment of the timing of deformation, shortening and shorten-ing strain rate. Trishear models are used to assess deformation in the Lenghu5 thrust belt. Based on trishear propagation geometric models, the Lenghu5 de-formation history is simulated using forward trishear modelling. A range of trishear modelling parameters is used to interpret the various structural styles presented. This provides new insights to the potential application of trishear mechanism in complex natural structures developed in different environments. Meso-scale detailed structural maps of exceptionally well-exposed outcrops are used to extract information on local fault geometry. Main thrust faults, minor thrust faults and accommodation normal faults are all mapped in detail, making it possible to evaluate the differences of fault architectures between different types of faults. Models are proposed to define the elements of fault zones. Fault zone evolution models are constructed in order to understand the dynamic pro-cess of the fault development. Micro-structural analysis (e.g., SEM) of rock samples is used for assessment of the deformation mechanisms associated with fault zone development. The vital influence of micro-scale deformation mechanisms on hydrocarbon sealing properties has been evaluated, in order to reveal the relationship between the deformation mechanism and hydrocarbon sealing behaviour. This work illustrates the value of a regional- to micro-approach on thrust fault evolution and hydrocarbon sealing behaviour, and aims to identify the critical parameters that contribute to improving fault seal analysis in thrust systems.
15
Boe, Jennifer Barber. "Removal of hydrocarbons from urban stormwater runoff by gravity separation." Thesis, This resource online, 1993. http://scholar.lib.vt.edu/theses/available/etd-10312009-020227/.
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Ramphaka, Lerato Priscilla. "Integrating 3D basin modelling concept to determine source rock maturation in the F-O Gas Field, Bredasdorp Basin (offshore South Africa)." Thesis, University of the Western Cape, 2015. http://hdl.handle.net/11394/5340.
Повний текст джерелаАнотація:
>Magister Scientiae - MScThe burial history, thermal maturity and petroleum generation history of the F-O Gas Field, Bredasdorp Basin have been studied using 3D basin and petroleum systems modelling approach. The investigated sedimentary basin for this study evolved around mid-late Jurassic to early Cretaceous times when Southern Africa rifted from South America. The F-O field is located 40 km SE of the F-A platform which supplies gas and condensate to the PetroSA ‘Gas to Liquid’ plant located in Mossel Bay. As data integration is an integral part of the applied modelling concept, 2D seismic profile and well data (i.e. logs and reports from four drilled wells) were integrated into a 3D structural model of the basin. Four source rock intervals (three from the Early Cretaceous stages namely; Hauterivian, Barremian, Aptian and one from the Late Cretaceous Turonian stage) were incorporated into the 3D model for evaluating source rock maturation and petroleum generation potential of the F-O Gas Field. Additionally, measured present-day temperature, vitrinite reflectance, source potential data, basin burial and thermal history and timing of source rock maturation, petroleum generation and expulsion were forwardly simulated using a 3D basin modelling technique. At present-day, Turonian source rock is mainly in early oil (0.55-0.7% VRo) window, while the Aptian and Barremian source rocks are in the main oil (0.7-1.0% VRo) window, and the Hauterivian source rock is mainly in the main oil (0.7-1.0% VRo) to late oil (1.0-1.3% VRo) window. In the entire four source rock intervals the northern domain of the modelled area show low transformation, indicated by low maturity values that are attributable to less overburden thickness. Petroleum generation begins in later part of Early Cretaceous, corresponding to high heat flow and rapid subsidence/ sedimentation rates. The Barremian and Aptian source rocks are the main petroleum generators, and both shows very high expulsion efficiencies. The modelling results however indicate that the younger Aptian source rock could be regarded as the best source rock out of the four modelled source rocks in the F-O field due to its quantity (i.e. highest TOC of 3%), quality (Type II with HI values of 400) and highest remaining potential. At present-day, ~1209 Mtons of hydrocarbons were cumulatively generated and peak generation occurred at ~43 Ma with over 581 Mtons generated. Finally, the results of this study can directly be applied for play to prospect risk analysis of the F-O gas field.
17
Razafimbelo, Eugène. "Le bassin de morondava (madagascar) : synthese geologique et structurale." Université Louis Pasteur (Strasbourg) (1971-2008), 1987. http://www.theses.fr/1987STR13184.
Повний текст джерелаАнотація:
La synthese des donnees geologiques et structurales du bassin de morondava conduit a modifier la nomenclature stratigraphique des formations sedimentaires du type "karroo". Dans le bassin, le controle tectonique de la sedimentation est realise par un jeu complexe mais permanent de failles en faisceaux denses. La fracturation continentale a permis la mise en place de roches effusives basaltes et gabbros, puis roches granito-syenitiques. L'epaisseur et la nature des formations sedimentaires du bassin de morondava sont propices a la naissance de gisements d'hydrocarbures
18
Lisk, Mark. "Fluid migration and hydrocarbon charge history of the vulcan sub-basin." Thesis, Curtin University, 2012. http://hdl.handle.net/20.500.11937/1932.
Повний текст джерелаАнотація:
A comprehensive examination of the hydrocarbon charge and formation water history of the central Vulcan Sub-basin, Timor Sea has been completed and a model developed to describe the evolution of the region’s petroleum systems. Reservoir horizons within the Mesozoic pre-, syn- and post-rift megasequences have been evaluated for their ability to host and retain oil and gas through a period of tectonic upheaval, associated with oblique plate collision in the Neogene. A coupled hydrocarbon-formation water model has been developed that describes two discrete formation water phases (W1 and W2) and three hydrocarbon phases (H1, H2, H3), with the timing of these events linked to important phases in the basin evolution.The Vulcan Sub-basin contains the components required to produce an effective petroleum system. The principal clastic reservoirs generally exhibit good porosity and permeability and are capped by effective, regionally extensive, seal rocks. A consistent paragenetic sequence can be recognised for Mesozoic reservoirs with early glauconite and pyrite phases preceding clay authigenesis. These early phases are in turn enclosed by quartz overgrowths that are subsequently enclosed by ankerite cement and in more deeply buried samples, filamentous illite. Source rocks are suitably located adjacent to these reservoirs, are organically rich and have experienced sufficient burial to promote thermal maturation and expulsion of generated hydrocarbons.The novel Grains with Oil Inclusions (GOI) fluid inclusion technique that allows the abundance of oil-filled fluid inclusions to be related to the maximum level of oil saturation experienced by a sandstone reservoir through time has been used to describe the charge history of a selection of wells from across the Vulcan Sub-basin. GOI data shows that the source rocks have been extremely productive, with three discernible hydrocarbon charge events recognised (H1, H2 and H3). An early gas charge (H1) appears to be widespread in the basin, but this may have been deleterious to regional prospectivity by reducing the volumetric capacity of traps that were well positioned to receive later oil charge.Stable isotope data from early formed clay and carbonate cements indicate connate waters extant during the first phase of hydrocarbon migration (H1) had mixed with meteoric water (W1) introduced into the reservoirs during periods of sub-aerial exposure associated with uplift related to rifting.A regionally extensive oil charge (H2), derived from Upper Jurassic mudstones, produced numerous, volumetrically significant, oil columns. GOI data shows that many of the current oil fields were once much larger and that many reservoirs that are now gas or water bearing also previously contained oil accumulations.Geochemical analysis of selected fluid inclusion oils (FIOs) show derivation from mixed marine and terrestrially derived source rocks of the Upper Jurassic Vulcan Formation. These oils form the first of two oil families that constitute the previously defined Jurassic Vulcan-Plover (!) petroleum system. In contrast the crude oils previously assigned to the second oil family and thought to have been derived from deltaic source rocks of the Middle Jurassic Plover Formation are not well represented in the FIOs. In addition a number of the FIOs are unlike either recognised oil family and show source rock characteristics that imply derivation from fully marine source rocks. These could represent either a previously unrecognised oil family or may reflect a true end member of the first family that has been mixed with the second family to produce an intermediate composition. The presence of the angiosperm marker Oleanane in some of the FIOs suggests a contribution from Cretaceous source rocks is also possible.The GOI data indicate high charge rates to structurally valid traps with at least one in three valid traps showing clear evidence of oil accumulation. Fluid inclusion palaeotemperature data, integrated with one dimensional (1D) basin models, produce a similar prediction of the charge timing with oil charge mostly from Eocene time. This agrees well with subsidence curves, which show a period of increased subsidence in the Paleocene that is likely to have promoted oil generation and expulsion into carrier beds used to facilitate oil migration into traps.Although an effective petroleum system can be demonstrated to have been present in the Tertiary, this has not been fully preserved due to events that post-dated hydrocarbon charge. The most significant of these has been the flexural bending of the lithospheric plate during oblique collision of the northwards moving Australian Plate with the eastwards moving S.E. Asian Plate. This collision produced a net extensional stress field throughout the Vulcan Sub-basin, resulting in widespread reactivation of deeper rift fault systems, and the formation of extensive arrays of shallow Miocene-Pliocene faults. Interaction between these fault populations has, in many cases, increased net-vertical structural permeability and led to breaching of hydrocarbon traps and the attendant leakage of oil and gas.Another major fluid-flow event that was controlled by the increase in structural permeability due to plate collision can also linked to the loss of hydrocarbons due to fault breach. A regionally extensive fluid-flow event, involving vertical, cross formation, migration of highly saline brine (W2) is indicated by fluid inclusion palaeo-salinity data. These palaeo-pore waters, with maximum salinities above 200,000 ppm NaCl equivalent, record the migration of high-salinity brines through Mesozoic and Tertiary sandstones. Fault controlled injection of brine from bedded salt at depths of up to 10 km is most likely the main source of this brine. Alternative salt sources in the drilled section are salt diapirs, but these are spatially restricted and their dissolution cannot reconcile the observed widespread distribution of these highly saline palaeo-fluids.In samples taken from intact hydrocarbon columns the absence of hyper-saline fluid inclusions suggests brine flow occurred after initial hydrocarbon charge. Further, high salinities seen in samples from recognised residual oil zones suggests that trap breach facilitated the ingress of high-salinity brines. Numerical simulations, utilised to test this hypothesis, produce outcomes that broadly match the observed distribution of samples with high salinity fluid inclusions.Brine flow from more deeply buried Palaeozoic strata also imparts a convective overprint on the conductive thermal background. Although not represented by the current geothermal conditions, thermal maturity data recording accumulated thermal stress, indicates localised heating of sediments immediately adjacent to faults bounding breached oil columns. The use of such anomalous maturity data when modelling hydrocarbon generation could lead to spurious conclusions if the restricted spatial extent of these convective effects is not considered.Aside from Neogene fault reactivation at least four additional processes have modified the preservation potential of the Jurassic Vulcan-Plover (!) petroleum system since the initial hydrocarbon charge. Although generally second order effects on a regional scale, these can be extremely important at the local scale. The first involves passive leak zones formed by reactivation of long-lived fault intersections that appear to control the trap capacity of the Skua oil field and likely play an important role more widely. Subsequent structural tilting during the Late Tertiary altered the spill-points of some hydrocarbon traps resulting in further redistribution of hydrocarbons. Demonstrable evidence of modification to spill-points after initial oil charge is recorded in the Skua Field where the original OWC is inclined, and can be explained by the establishment of north-westerly tilting.The third process to affect the system was a late stage gas charge (H3) that displaced oil from many of the traps that today contain gas. Considerable potential for downdip or displaced oil legs in the Swan and Oliver fields respectively is inferred.The final process to modify the petroleum system involved a significant increase in the magnitude of the horizontal stress component within the regional stress field, imparted by the jamming of the Banda Arc subduction zone by buoyant Australian Continental crust. The resultant reduction in observed extensional faulting likely led to an improvement in trap integrity such that heavily reactivated traps with access to charge could be successfully refilled.Data acquired by this study provides a base map of the charge history in the Vulcan Sub-basin with which to test the applicability of models proposed to predict the retention of hydrocarbons in yet to be drilled traps. These data already have been used to test models that utilise a variety of seepage detection methodologies including airborne and satellite based direct detection as well as indirect methods such as hydrocarbon related diagenesis. In the future, rigorous integration of these data into numerical models of fault reactivation that describe the complex interplay between stress, fluid-flow and regional tectonics will contribute to a better understand the mechanisms controlling fault breach in this region and in sedimentary basins elsewhere.
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Diyarbakirli, Ali Can. "Stratigraphic Analysis and Reservoir Characterization of the Late Oligocene-Early Miocene, Upper Yenimuhacir Group, Thrace Basin, Turkey." Thesis, Virginia Tech, 2016. http://hdl.handle.net/10919/73651.
Повний текст джерелаАнотація:
The Thrace Basin, NW Turkey, is one of the most important basins in Turkey in terms of hydrocarbon potential. Previous studies, starting in the 1930s, focused on tectonics, basin evolution, sedimentation and stratigraphy, depositional systems, and hydrocarbon potential. Eocene turbiditic sandstones and reefal limestones, and Oligocene deltaic sandstones are the major reservoir targets in the basin today. The focus of this research is the Upper Oligocene deltaic sandstones, namely the Danismen and Osmancik formations, which contain potential hydrocarbon reservoirs. The aims of research were to develop a better understanding of the geometric configuration of the Oligocene strata and to identify potential reservoirs within the study area. Accordingly, the geometric configurations of the strata were delineated using 3D seismic reflection data whereas petro-physical properties of the target formations were determined using wireline logs from three wells. A right-lateral strike slip or reverse fault system and associated NW-SE trending asymmetric fold extend across the study area. Both the fault system and the fold are truncated beneath the Miocene unconformity and are thus dated as late Oligocene to early Miocene in age. The Miocene unconformity forms a stratigraphic trap whereas the fault system and associated fold construct a NW-SE trending structural trap. Hydrocarbon-bearing, five main clean sandstone (shale volume less than %10) intervals were identified using wireline logs and evaluated as potential targets. Hydrocarbon concentrations increase through the fold structure. Thus, the fault system and the associated asymmetric fold were the main factors that affected the zonal distribution of hydrocarbons in the study area.Master of Science
20
Quaglia, Laurent. "Contribution à l'étude des écoulements diphasiques avec capillarité." Thesis, Aix-Marseille, 2017. http://www.theses.fr/2017AIXM0567.
Повний текст джерелаАнотація:
La modélisation numérique de la migration des hydrocarbures dans les bassins sédimentaires permet de déterminer les accumulations d’hydrocarbures au sein des formations géologiques. A partir de cela on peut prévoir la hauteur d’hydrocarbure piégé. Cette détermination est essentielle dans l’industrie du pétrole. Cependant grâce à certaines études, on a pu s’apercevoir que des erreurs numériques pouvaient apparaître lors de l’utilisation de pression capillaires polynomiales. Dans cette thèse, nous travaillons principalement sur les modèles dits de Darcy et nous évoquons sommairement les modèles de type percolation. L’objectif de ce travail est de fournir de nouveaux modèles des pressions capillaires, donnant de meilleurs résultats que ceux actuellement utilisés. Dans un premier temps, nous décrivons les mécanismes de la migration des hydrocarbures dans les couches. Ensuite nous étudions plus attentivement les lois des pressions capillaires permettant l’écoulement des fluides. Puis nous établissons la discrétisation, suivant la méthode des volumes finis, du problème. Dans la partie suivante nous testons en une dimension de nouveaux modèles de pressions capillaires affines par morceaux. Puis dans une autre partie, nous faisons les tests en deux dimensions de ces modèles auxquels nous rajoutons un autre modèle, bâti à partir des deux précédents. En conclusion, nous synthétisons l’ensemble des résultats et évoquons certaines perspectives concernant l’amélioration des modèles étudiésNumerical modeling of hydrocarbon migration in sedimentary basins makes it possible to determine hydrocarbon accumulations within geological formations. From this it is possible to predict the trapped hydrocarbon height. This determination is essential in the petroleum industry. However, thanks to some studies, it has been found that numerical errors can occur when using polynomial capillary pressure. In this thesis, we work mainly on the so-called models of Darcy and we briefly discuss percolation-type models. The objective of this work is to provide new models of capillary pressures, giving better results than those currently used. First, we describe the mechanisms of hydrocarbon migration in the layers. Then we study more closely the laws of capillary pressures allowing the flow of fluids. Then we establish the discretization, according to the finite volume method, of the problem. In the next part we test in one dimension new models of capillary pressures affine in pieces. Then in another part, we do the two-dimensional tests of these models to which we add another model, built from the two previous ones. In conclusion, we summarize all the results and discuss some perspectives concerning the improvement of the studied models
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Clarke, Stuart. "Faulting, fault zone processes and hydrocarbon flow through three-dimensional basin models." Thesis, Keele University, 2001. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.394652.
Повний текст джерела
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Machado, Vladimir Alberto Gouveia. "Sand provenance, diagenesis and hydrocarbon charge history of the Kwanza Basin, Angola." Thesis, University of Aberdeen, 2007. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=225701.
Повний текст джерелаАнотація:
Sand provenance in the Kwanza Basin, Angola, is assessed using conventional and varietal heavy mineral analysis. There are contrasting heavy mineral signatures in the north and south of the basin separated by a hybrid zone. These contrasts are attributed to different hinterland geology. Heavy mineralogy, sand body distribution and prominent structures allowed the subdivision of the Kwanza Basin into five depositional domains. Heavy mineral indices filter important provenance signatures in space and time in addition to providlng tectonic and geomorphologic information. Quantitative and qualitative thermal and composition information was obtained from fluid inclusions using UV fluorescence and microthermometry. There were at least two pulses of hydrocarbon generation and migration from source rocks in the basin based on homogenization temperatures of 52-129°C, geochemical characterization of oil shows from proprietary data, and Genesis basin modelling: 1) during Albian time, rift-related high heat flow triggered the first pulse, and 2) high rates of sedimentation led to a burial-induced pulse during the Neogene-Quaternary. There are three main controls on diagenesis: stratigraphy and facies; thermal history; and provenance. Significant authigenic minerals (illite, smectite, dolomite, quartz and feldspar) were only noted in Cenomanian or older rocks. Apatite fission track analysis (AFTA) yields a record of the temperature regime experienced by the basin and basement through the pre-rift, syn-rift and post-rift stages. There were three main tectono-thermal events in the basin: 1) pre-rift and early syn-rift cooling; 2) a post-rift period of tectonic quiescence (Cretaceous to early Tertiary); interrupted by 3) a rapid cooling (denudation) due to epeirogenic uplift of the Inner Kwanza Basin and hinterland at ca. 23 Ma. Miocene denudation of the Inner Kwanza Basin and the hinterland is mirrored by a burial-related temperature increase in the Outer Kwanza Basin. This source to sink correlation indicates a period of bypassed sedimentation into the Outer Kwanza Basin and possibly onto the abyssal plain of Angola. Keywords: Kwanza Basin, diagenesis, provenance, heavy minerals, fluid inclusion, microthermometry, AFTA, basin modelling, hydrocarbon charge.
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Bird, Peter Cameron. "Tectono-stratigraphic evolution of the West Orkney Basin : implications for hydrocarbon exploration." Thesis, Cardiff University, 2014. http://orca.cf.ac.uk/73653/.
Повний текст джерелаАнотація:
The West Orkney Basin is situated in a frontier hydrocarbon region of the United Kingdom Continental Shelf. This study presents a reappraisal of the tectono-stratigraphic development and petroleum potential of the basin, and is based on a recent compilation and partial reprocessing of all the available 2D reflection seismic for the area. Evidence for the presence of Devonian lacustrine source-rocks in the basin is demonstrated by the recognition of a syn-rift sequence overlying basement, which comprises two packages of contrasting seismic facies characteristics, which are correlateable to onshore Devonian source-rock and reservoir facies. The syn-rift sequence is truncated at unconformity; that is related to Late Carboniferous inversion of the Great Glen-Walls Boundary Fault system. A second major phase of rifting within the basin, with formation of new faults and reactivation of pre-existing Devonian faults, is interpreted to have initiated in the Late Permian and dwindled into the Early Jurassic. Subsequent extensive exhumation events occurred in the Mid-Jurassic to Early Cretaceous and Cenozoic, with removal of about 2.5 km of Upper Triassic to Lower Jurassic sediments and perhaps 0.5 to 1 km of Upper Cretaceous rocks. Timing of hydrocarbon generation from Devonian source-rocks was modelled using Genesis 1D basin-modelling software from Zetaware, and the results from this indicate that it most probable that the majority of hydrocarbon generation in the basin preceded the end of the second phase of rifting in the basin (Late Permian to Early Jurassic). Therefore, the major risks with play-concepts based on a Devonian source-rock are considered to be seal integrity during multiple and prolonged uplift events.
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Magoba, Moses. "Petrophysical evaluation of sandstone reservoir of well E-AH1, E-BW1 and E-L1 Central Bredasdorp Basin, offshore South Africa." University of the Western Cape, 2014. http://hdl.handle.net/11394/4462.
Повний текст джерелаАнотація:
Magister Scientiae - MScThe Bredasdorp basin is a sub-basin of the greater Outeniqua basin. It is located off the south coast, Southeast of Cape Town, South Africa. This basin is one of the largest hydrocarbon (mainly gas) producing basins within Southern Africa. The petrophysical characteristic of the E-block sandstone units within the Bredasdorp basin has been studied to evaluate their hydrocarbon potential. The data sets used in this research were wireline logs (Las format), core data, and geological well completion reports. The three studied wells are E-AH1, E- BW1 and E-L1. The evaluated interval ranges from 2000.33m to 3303.96m in depth with reference to Kelly bushing within the wells. The sandstone reservoirs of the Bredarsdorp basin are characterized by a range of stacked and amalgamated channels. They originated from materials eroded from pre-existing high stand shelf sandstone and transported into the central Bredarsdorp basin by turbidity current. These sandstones are generally in both synrift and drift section. The basin is thought to have developed from fan deltas and stream overwhelmed to water dominated delta. River dominated deltaic system progresses southward over the Northern edge of the central Bredasdorp basin. The Interactive Petrophysics (IP) software has been used extensively throughout the evaluation and development of interpretation model. The lithofacies of the rock units were grouped according to textural and structural features and grain sizes of well (E-AH1, E-BW1 and E-L1). Four different facies (A, B, C and D) were identified from the cored intervals of each well. Facies A was classified as a reservoir and facies B, C and D as a non-reservoir. Detailed petrophysical analyses were carried out on the selected sandstone interval of the studied wells. The cut-off parameters were applied on the seven studied sandstone interval to distinguish between pay and non-pay sand and all intervals were proved to be producing hydrocarbon. Volume of clay, porosity, water saturation and permeability were calculated within the pay sand interval. The average volume of clay ranged from 23.4% to 25.4%. The estimated average effective porosity ranged from 9.47% to 14.3%. The average water saturation ranged from 44.4% to 55.6%. Permeability ranged from 0.14mD to 79mD. The storage and flow capacity ranged from 183.2scf to 3852scf and 2.758mD-ft to 3081mD-ft respectively. The geological well completion reports classify these wells as a gas producing wells. E-L1 is estimated to have a potential recoverable gas volume of 549.06 cubic feet, E-BW1 is estimated to have 912.49 cubic feet and E-AH1 is estimated to have 279.69 cubic feet.
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Acho, Collins Banajem. "Assessing hydrocarbon potential in cretaceous sediments in the Western Bredasdorp Sub-basin in the Outeniqua Basin South Africa." University of the Western Cape, 2015. http://hdl.handle.net/11394/4807.
Повний текст джерелаАнотація:
>Magister Scientiae - MScThe Bredasdorp Basin is one of the largest hydrocarbon producing blocks within Southern Africa. The E-M field is situated approximate 50 km west from the FA platform and was brought into commission due to the potential hydrocarbons it may hold. If this field is brought up to full producing capability it will extend the lifespan of the refining station in Mosselbay, situated on the south coast of South Africa, by approximately 8-10 years. This study is focused in block 9 off shore western part of the Bredasdorp Basin in the main Outeniqua Basin South Africa. Cretaceous Sandstone reservoirs are commonly heterogeneous consequently they may require special methods and techniques for description and evaluation. Reservoir characterization is the study of the reservoir rocks, their petrophysical properties, the fluids they contain or the manner in which they influence the movement of fluids in the subsurface. The main goal of the research is to assess the potentials of hydrocarbons in Cretaceous sediments in the Bredasdorp Basin through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model for wells (E-BB1, E-BD2, EA01) in the Bredasdorp Basin. Porosity and permeability relationships, wire-line log data have been examined and analysed to determine how the porosity and permeability influence reservoir quality which further influences the potential of hydrocarbon accumulation in the reservoirs. The reservoir sandstone is composed mainly of fine to medium grained Sandstones with intercalation of finger stringers of Siltstone and Shale. In carrying out this research the samples are used to characterize reservoir zones through core observation, description and analyses and compare the findings with electronic data obtained from Petroleum Agency of South Africa (PASA). Secondary data obtained from (PASA) was analysed using softwares such as Interactive Petrophysics (IP), Ms Word, Ms excel and Surfer. Wireline logs of selected wells (E-BB1, E-BD2, E-A01) were generated, analysed and correlated. Surfer software also used to digitize maps of project area, porosity and permeability plotted using IP. Formation of the Bredasdorp Basin and it surrounding basins during the Gondwana breakup. The Bredasdorp Basin consists mainly of tilting half graben structures that formed through rifting with the break-up of Gondwanaland. The model also revealed that these faults segregate the reservoir which explains the pressure loss within the block. The production well was drilled, confining pressure relieved and pressure dropped hence production decreases. The age, transportation, deposition and thermal history of sediment in the basin, all plays a vital role in the type of hydrocarbon formation. Structural features such as faults, pore spaces determines the presence of a hydrocarbon in the reservoir. Traps could be stratigraphic or structural which helps prevent the migration of hydrocarbons from the source rock to reservoir rock or from reservoir rock to the surface over a period of time. The textural aspects included the identification of grain sizes, sorting and grain shapes. The diagenetic history, constructed from the results of the reservoir quality study revealed that there were several stages involved in the diagenetic process. It illustrated several phases of cementation with quartz, carbonate and dolomite with dissolution of feldspar. A potentially good reservoir interval was identified from the data and was characterized by several heterogeneous zones. Identifying reservoir zones was highly beneficial during devising recovery techniques for production of hydrocarbons. Secondary recovery methods have thus been devised to enhance well performance. As recommendation, additional wells are required to appraise the E-M structure and determine to what extent the cement present in the basin has affected fluid flow as well as the degree of sedimentation that could impede fluid flow. There are areas still containing untapped resources thus the recommendation for extra wells. This research may well be reviewed with more data input from PetroSA (wells, seismic and production data) for additional studies, predominantly with respect to reservoir modelling and flow simulation. Based on the findings of this research, summary of calculated Net Pay shows that in well E-BB1, reservoir (1) is at depth 2841.5m – 2874.9m has a Gross Thickness of 33.40m, Net Pay of 29.72 and Pay Summary of 29.57 and reservoir (2) has depth of 2888.1m – 2910.5m, Gross Thickness of 22.40m, Net Pay of 19.92m and Pay summary of 1.48m. Well E-AO1 has depth from 2669.5m – 2684.5m and Gross Thickness of 15.00m and has Net Pay of 10.37m and Pay Summary of 10.37m. Based on the values obtained from the data analysed the above two wells displays high potential of hydrocarbon present in the reservoirs. Meanwhile well E-BD2 has depth from 2576.2m – 2602.5m and has Gross Thickness of 350.00m, Net Pay of 28.96m and Pay Summary of 4.57 hence from data analysis this reservoir displays poor values which is an indication of poor hydrocarbon potentials.
26
Huyen, Bui Thi Thanh. "Basin development and hydrocarbon potential of the Song Hong basin, Vietnam, insights from numerical simulation and seismic interpretation." 京都大学 (Kyoto University), 2006. http://hdl.handle.net/2433/143965.
Повний текст джерелаАнотація:
Kyoto University (京都大学)0048
新制・課程博士
博士(工学)
甲第12266号
工博第2595号
新制||工||1366(附属図書館)
24102
UT51-2006-J259
京都大学大学院工学研究科社会基盤工学専攻
(主査)教授 松岡 俊文, 教授 芦田 讓, 教授 朝倉 俊弘
学位規則第4条第1項該当
27
Ma, KeYang. "Hydrocarbon source and depositional environments in the central Papual Basin, Papua New Guinea /." [St. Lucia, Qld.], 2005. http://www.library.uq.edu.au/pdfserve.php?image=thesisabs/absthe18901.pdf.
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Davies, Christopher Paul Norman, A. Rozendaal, and B. V. Burger. "Hydrocarbon evolution of the Bredasdorp Basin, offshore South Africa : from source to reservoir." Thesis, Stellenbosch : University of Stellenbosch, 1997. http://hdl.handle.net/10019.1/4936.
Повний текст джерелаАнотація:
Thesis (PhD (Geology))--University of Stellenbosch, 1997.1123 leaves printed on single pages, preliminary pages and numbered pages 1-286. Includes bibliography, list of figures and tables and explanation of abbreviations used.
Digitized at 600 dpi grayscale to pdf format (OCR), using a Bizhub 250 Konica Minolta Scanner.
ENGLISH ABSTRACT: This first comprehensive study of the petroleum geochemistry of the Bredasdorp Basin, and the adjacent Southern Outeniqua Basin, documents the characteristic large number of hydrocarbon shows and the four regionally distinctive marine source rocks. Detailed correlation of reservoired hydrocarbons with source rock bitumens shows that two source rocks have expelled oil in commercial quantities and two others have expelled commercial quantities of wet gas/condensate. In contrast with earlier studies which indicated that thermal 'gradualism' prevailed, this study indicates that the post-rift thermal history of the basin is very complex. Post-rift cool-down is punctuated by periods of rapidly increasing heat flow resulting in much of the maturation being localised in time. These periods of increased heating coincide with regional plate tectonism. The associated thermal uplift and downwarp effects govern the periods of trap formation and control the hydrocarbon migration direction. Migration distances of these hydrocarbons are described and show inter alia that oil migrates no more than -7-10 km but gas migrates regionally. Two regional episodes of meteoric water flushing reduce sandstone cementation in palaeo-highs forming potential reservoirs at specific times. The unusually low salinity of remnants of this water in some sandstones help characterise these two main migration conduits. A highly detailed hydrocarbon correlation scheme derived from gas, light oil and biomarker data has been established which differentiates products of the four active source rocks and helps characterise the oil-oil, oil-source and source-source pairs. It is evident from these correlations that two periods of migration and reservoiring occurred at 50-60 Ma and 0-10 Ma. As a result, source-reservoir plays which characterise certain areas of the basin as predominantly oil or gas prone can be described. These correlations also highlight areas where mixtures of hydrocarbons are common and where some of the early reservoired oil has been displaced to new locations, constituting potential new exploration plays. Source rocks for some of the analysed hydrocarbons have yet to be found and may not even have been drilled to date. One such source rock appears to be located in the Southern Outeniqua Basin, making that area a potential target for further exploration. This study resolved the common heritage of the source rocks and reservoir sandstones which form part of the Outeniqua petroleum system. The hydrocarbon volumes available to this system show that by world standards it is indeed significant.
AFRIKAANSE OPSOMMING: Die groot aantal koolwaterstof voorkomste asook vier streekskenmerkende mariene brongesteentes word in hierdie eerste omvattende studie van die petroleumgeochemie van die Bredasdorp-kom en die aangrensende Suidelike Outeniqua-kom saamgevat. Gedetaileerde korrelasies van die opgegaarde koolwaterstowwe met brongesteente bitumen, dui daarop dat twee van die vier geidentifiseerde brongesteentes olie in kommersiele hoeveelhede uitgeset het. Die ander twee het kommersiele hoeveelhede nat gas-kondensaat uitgeset. In teenstelling met vroeer studies wat daarop gedui het dat termale 'gradualisme' voorgekom het, dui hierdie studie daarop dat die na-riftermale geskiedenis van die kom baie meer kompleks is. Verskeie periodes van versnelde toename in hittevloei het voorgekom in die na-rifse verkoeling. Dit het daartoe gelei dat veroudering plaaslik binne 'n beperkte tydsverloop plaasvind. Hierdie periodes van hittetoename stem ooreen met die regionale plaattektoniek. Die geassosieerde termiese opheffing en afwaartse vervormingseffek, beheer die totstandkoming van opvanggebiede en die migrasierigting van die koolwaterstowwe. Migrasie-afstande van die koolwaterstowwe word bespreek en wys inter alia daarop dat olie nie verder as -7-10 km beweeg nie, maar gasmigrasie vind regionaal plaas. Twee kort episodes van meteoriese wateruitsetting, het sandsteensementasie in palaeohoogsliggende gebiede verminder wat potensiele reservoirs gevorm het op spesifieke tye. Die ongewone lae soutvlakte van oorblyfsels van die water in sekere sandstene help om die twee vernaamste migrasieroetes te kenmerk. 'n Hoogs omvattende koolwaterstof-korrelasieskema wat van gas, ligte olie en biomerkerdata verkry is, is opgestel. Die skema het onderskei tussen produkte van die vier aktiewe brongesteentes en help om die olie-olie, olie-bron en bron-bron pare te karakteriseer. Dit is duidelik van die korrelasies dat twee periodes van migrasie en opgaring plaasgevind het ongeveer teen -50-60 Ma en 0-10 Ma. Gevolglik kan bronreservoir omskrywings wat sekere dele van die kom karakteriseer as grotendeels olie of gas-ontvanklik beskryf word. Hierdie korrelasies beklemtoon ook areas waar mengsels van koolwaterstowwe algemeen voorkom en waar sekere van die vroeer opgegaarde olie verplaas is na nuwe lokaliteite, wat nuwe eksplorasieteikens daarstel. Brongesteentes vir sekere van die ge-analiseerde koolwaterstowwe, moet nog gevind word en is tot op hede nog nie raakgeboor nie. Een so 'n brongesteente kom voor in die Suidelike Outeniqua-kom, wat daardie area 'n potenslele teiken vir verdere eksplorasie maak. Die studie het die gesamentlike oorsprong van die brongesteente en reservoirsandsteen, wat deel is van die Outeniqua Petroleumsisteem, geidentifseer. Die koolwaterstofvolumes wat beskikbaar is vir die sisteem wys dat, gemeet teen wêreldstandaarde, dit wel beduidend is.
29
Moore, Myles Thomas. "Noble Gas and Hydrocarbon Geochemistry of Coalbed Methane Fields from the Illinois Basin." The Ohio State University, 2016. http://rave.ohiolink.edu/etdc/view?acc_num=osu1462561493.
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30
Mert-gauthier, Esra. "Modeling Permian Petroleum System Of Northeast Netherlands: Hydrocarbon Generation And Migration." Master's thesis, METU, 2010. http://etd.lib.metu.edu.tr/upload/12612508/index.pdf.
Повний текст джерелаАнотація:
Groningen Gas Field is located within the southern part of the South Permian Basin in
the northeast Netherlands. Since several wells have been producing from the
Carboniferous-Permian Petroleum System, the field is considered as mature for
hydrocarbon exploration. More detailed work is necessary to evaluate further
exploration and development opportunities. Thus, evaluation of the subsurface has been
carried out as part of the petroleum system concept by using the basin modeling.
In this study, seismic interpretation was performed by using 3-dimensional seismic and
borehole data with Petrel software in order to understand stratigraphy and structural
settings of the area. PetroMod basin analysis software has been used for 1-dimensional
and 2-dimensional basin modeling study by integrating interpreted geophysical,
geological and geochemical data.
Results show that the most recognized traps were formed during pre-Zechstein, and the
major generation-migration and accumulation of hydrocarbon commenced during
Middle Jurassic and continues to the present time. Since the timing of main hydrocarbon
generation varies spatially and has begun after trap formation, both early and late
migration enhances the potential of the porous Upper Rotliegend reservoirs. Prospective
hydrocarbon traps may occur in the southwestern regions of the basin due to shallower
depth of burial. On the other hand, all local structural highs that formed as a result of
salt movement create potential traps in the region.
31
Al-Arouri, Khaled R. "Petroleum geochemistry, source rock evaluation and modelling of hydrocarbon generation in the southern Taroom Trough, with particular reference to the Triassic Snake Creek Mudstone /." Title page, abstract and contents only, 1996. http://web4.library.adelaide.edu.au/theses/09PH/09pha321.pdf.
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Nelson, Donald E. Jr. "Polycyclic Aromatic Hydrocarbons in Sediments of Marinas, Western Basin Lake Erie, U.S.A." University of Toledo / OhioLINK, 2009. http://rave.ohiolink.edu/etdc/view?acc_num=toledo1245342686.
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Serafini, K. M. "Hydrocarbon source rock potential of the Western Otway Basin : a geochemical and petrological study /." Title page, abstract and contents only, 1989. http://web4.library.adelaide.edu.au/theses/09SB/09sbs481.pdf.
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34
Hrouda, Mohamed. "The hydrocarbon source potential of the palaeozoic rocks of the Ghadames Basin, NW Libya." Thesis, University of Newcastle Upon Tyne, 2005. http://hdl.handle.net/10443/1054.
Повний текст джерелаАнотація:
Lower Silurian and Upper Devonian organic-rich "hot shales" are the source of almost all Palaeozoic oils in North Africa and the Middle East. They are also developed in the Ghadames Basin, and a better understanding of their organic facies character, maturity and their correlation to Palaeozoic oils of the basin is considered crucial for the future oil exploration strategy. Core and ditch cuttings samples from the alternating transgressive and regressive marine sandstone and shales of the Tanezzuft, Acacus, Tadrart, Ouan Kasa, Aouinet Ouenine, and Tahara formations are investigated using a combination of organic geochemistry, palynofacies and organic petrology. The bulk geochemical results demonstrate the presence of various organic-rich horizons within the Silurian and Devonian formations. The total organic carbon (TOC) values are generally between 0.5 and 25.0%. The highest TOC values are measured within the dark-coloured non-bioturbated graptolitic "hot shales" of the Silurian lower Tanezzuft Formation (average 7%), and the Devonian Aouinet Ouenine Formation (average 2%); other formations such as Tahara Sandstone Formation contain some thin black shales interbeds that have an average TOC of 4.5%. Hydrogen indices (HI) are mostly below 450,150-435 in the lower Tanezzuft Formation, and reaching 50-300 in the Aouinet Ouenine Formation. Palynofacies analysis permits the recognition of different organic facies: a terrestrially-dominated oxic facies in the Upper Devonian, oxic nearshore shallow marine to proximal shelf facies enriched in thin-walled prasinophyte algal phycomata (leiospheres) with low AOM and phytoclasts in alternating sandstone and shale of the Upper and Lower Silurian, and dysoxic-anoxic hemipelagic facies dominated by well preserved AOM (genetically oil-prone Type II kerogen) in the Lower Silurian lower Tanezzuft Formation `hot-shale'. Results from 25 boreholes distributed throughout the basin indicate a significant spatial variation in the Silurian hot shales, including significant variation in gamma ray values, hot shale thickness and organic facies quality. Maturity evaluation based on Tmax, SCI, ACI, %VRE, biomarker and aromatic hydrocarbon distributions for Lower Silurian lower Tanezzuft "hot-shale" source rock facies revealed a trend of increasing maturity from middle mature (oil expulsion zone) in the north and south east to very mature (gas generation zone) towards the central and southwestern parts of the Ghadames Basin. The Upper Devonian samples are immature in the northern and south eastern parts of the basin and mature in the southwestern and central parts of the basin. Oil-source correlations revealed that all the analysed Palaeozoic oils of the Ghadames Basin display similar facies features to the Lower Silurian Tanezzuft Formation source rock facies. Therefore there is a high probability that these oils were generated from the Lower Silurian `hot-shale' source rocks. Maturity evaluation of the oil samples based on the biomarker and aromatic hydrocarbon ratios revealed that the oil samples collected from the oil fields located in the south and southwestern parts of the basin are more mature than the oil samples collected from the northern parts of the basin. This is consistent with the maturity trends of the source rocks of the Ghadames Basin. Most of the Upper Devonian source rock samples have unusual proportions of the 20S isomers (relative to 20R isomers) of the C29 steranes, with values of more than 55% 20S. Such high values could be due to factors other than maturity.
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McLaughlin, Fiona Ann. "The Canada basin, 1989-1995, upstream events and far-field effects of the Barents Sea branch." Thesis, National Library of Canada = Bibliothèque nationale du Canada, 2000. http://www.collectionscanada.ca/obj/s4/f2/dsk2/ftp03/NQ48224.pdf.
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Nelson, Donald E. "Polycyclic aromatic hydrocarbons in sediments of marinas, Western Basin Lake Erie, U.S. A. /." Connect to full text in OhioLINK ETD Center, 2009. http://rave.ohiolink.edu/etdc/view?acc%5Fnum=toledo1245342686.
Повний текст джерелаАнотація:
Thesis (M.S.)--University of Toledo, 2009.Typescript. "Submitted as partial fulfillments of the requirements for The Master of Science in Geology." "A thesis entitled"--at head of title. Bibliography: leaves 99-109.
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Mohammed, Muneef Mahjoob. "Stratal architecture and structural evolution of the Orange Basin, offshore Namibia : implications on hydrocarbon prospectivity." Thesis, University of Leeds, 2013. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.616299.
Повний текст джерелаАнотація:
Despite a significant increasing interest in the hydrocarbon system in deep water continental margins, the controls on the development of hydrocarbon system in these areas remain poorly constrained. The integration between the tectonostratigraphic evolution and hydrocarbon system modelling of the Namibian continental margin has provided new insights into the understanding of the main controls on the hydrocarbon system in deep water margins. The tectono-stratigraphic evolution of the Namibian margin has been divided into four main phases (pre-rift, syn-rift, transition and post-rift) which are separated by regional unconformities. The late syn-rift phase shows a significant thickness variation that is not controlled by faulting. This is considered to be depth dependent stretching. Towards the west, this thickness is covered by the seaward dipping reflectors (SDRs) which represent the initial phase of sea floor spreading. The transition from the rift to the post-rift phase is characterised by development the anoxic conditions that result in deposition of the organic rich Aptian source rock which represent the main source rock interval of the Kudu gas field. The high resolution of the seismic data has enabled more details on the development of the overburden (post-rift phase) of the margin to be obtained. The post-rift overburden has been subdivided into a number of second order and third order depositional sequences that are bounded by type-1 sequence boundaries. The tectono-stratigraphic evolution revealed that the margin has undergone two main tectonic uplift events at the end of Late Cretaceous and Late Tertiary resulting in a rapid switch in the location of sediment accumulations towards the middle and outer margin. The switch in the location of deposition has resulted in an increase of the burial and temperature in the deep water margin, and consequently an increase of the maturation of source rock intervals in this area as is documented in the results of the hydrocarbon system modelling. This is likely to have implications for other mature passive margin basins .
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Ramirez-Caro, Daniel. "Rare earth elements (REE) as geochemical clues to reconstruct hydrocarbon generation history." Thesis, Kansas State University, 2013. http://hdl.handle.net/2097/16871.
Повний текст джерелаАнотація:
Master of ScienceDepartment of Geology
Matthew Totten
The REE distribution patterns and total concentrations of the organic matter of the Woodford shale reveal a potential avenue to investigate hydrocarbon maturation processes in a source rock. Ten samples of the organic matter fraction and 10 samples of the silicate-carbonate fraction of the Woodford shale from north central Oklahoma were analyzed by methods developed at KSU. Thirteen oil samples from Woodford Devonian oil and Mississippian oil samples were analyzed for REE also. REE concentration levels in an average shale range from 170 ppm to 185 ppm, and concentration levels in modern day plants occur in the ppb levels. The REE concentrations in the organic matter of the Woodford Shale samples analyzed ranged from 300 to 800 ppm. The high concentrations of the REEs in the Woodford Shale, as compared to the modern-day plants, are reflections of the transformations of buried Woodford Shale organic materials in post-depositional environmental conditions with potential contributions of exchanges of REE coming from associated sediments. The distribution patterns of REEs in the organic materials normalized to PAAS (post-Archean Australian Shale) had the following significant features: (1) all but two out of the ten samples had a La-Lu trend with HREE enrichment in general, (2) all but two samples showed Ho and Tm positive enrichments, (3) only one sample had positive Eu anomalies, (4) three samples had Ce negative anomalies, although one was with a positive Ce anomaly, (5) all but three out of ten had MREE enrichment by varied degrees. It is hypothesized that Ho and Tm positive anomalies in the organic materials of the Woodford Shale are reflections of enzymic influence related to the plant physiology. Similar arguments may be made for the Eu and the Ce anomalies in the Woodford Shale organic materials. The varied MREE enrichments are likely to have been related to some phosphate mineralization events, as the Woodford Shale is well known for having abundant presence of phosphate nodules. The trend of HREE enrichment in general for the Woodford Shale organic materials can be related to inheritance from sources with REE-complexes stabilized by interaction between the metals and carbonate ligands or carboxylate ligands or both. Therefore, a reasonable suggestion about the history of the REEs in the organic materials would be that both source and burial transformation effects of the deposited organic materials in association with the inorganic constituents had an influence on the general trend and the specific trends in the distribution patterns of the REEs. This study provides a valuable insight into the understandings of the REE landscapes in the organic fraction of the Woodford Shale in northern Oklahoma, linking these understandings to the REE analysis of an oil generated from the same source bed and comparing it to oil produced from younger Mississippian oil. The information gathered from this study may ultimately prove useful to trace the chemical history of oils generated from the Woodford Shale source beds.
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Salie, Sadiya. "The effects of minerals on reservoir properties in block 3A and 2C, within the orange basin, South Africa." University of the Western Cape, 2018. http://hdl.handle.net/11394/6588.
Повний текст джерелаАнотація:
>Magister Scientiae - MScThe reservoir quality of the Orange Basin, offshore South Africa is known to be immensely impaired by the presence of authigenic minerals. The collective effects of burial, bioturbation, compaction and chemical reactions between rocks, fluid and organic matter conclusively determined the quality of reservoirs within the Orange basin. The aim of this study was to provide information on the quality of reservoirs within the Orange Basin. Data used to conduct this study include wireline logs (LAS format), well completion reports and core samples from potential reservoir zones of wells K-A2, K-A3 and K-E1. To accomplish the aim, petrophysical parameters were calculated, such as porosity, permeability and water saturation. Besides, depositional environments were identified using gamma ray log and core logging techniques. Thirdly, petrographic studies were supporting techniques in understanding how various minerals and diagenetic processes play a role in reservoir characterisation. Geophysical wireline logs (Gamma ray, Resistivity, Bulk density and Caliper) allowed for the estimation of the three main reservoir properties; namely: porosity, water saturation and permeability. The porosity calculations revealed a range of 3-18% for well K-A2, 2%-13% for well K-A3 and 3%-16% for well K-E1. The permeability’s ranged from 0.08-0.1 mD and 0.001-1.30 mD for K-A3 and K-E1, respectively. Thus, the findings of the petrophysical evaluation of the wells in Interactive Petrophysics indicated that the reservoir intervals of wells K-A2, K-A3 and K-E1 are of poor to good quality. Based on the core analyses, the depositional environment is mostly shallow marine, specifically tide dominated for well K-A2, sandstone channel for well K-A3 and intertidal environment for well K-E1. These environments were confirmed by XRD, revealing glauconite as the prominent mineral.
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Parker, Irfaan. "Petrophysical evaluation of sandstone reservoirs of the Central Bredasdorp Basin, Block 9, offshore South Africa." Thesis, University of the Western Cape, 2014. http://hdl.handle.net/11394/4661.
Повний текст джерелаАнотація:
>Magister Scientiae - MScThis contribution engages in the evaluation of offshore sandstone reservoirs of the Central Bredasdorp basin, Block 9, South Africa using primarily petrophysical procedures. Four wells were selected for the basis of this study (F-AH1, F-AH2, F-AH4, and F-AR2) and were drilled in two known gas fields namely F-AH and F-AR. The primary objective of this thesis was to evaluate the potential of identified Cretaceous sandstone reservoirs through the use and comparison of conventional core, special core analysis, wire-line log and production data. A total of 30 sandstone reservoirs were identified using primarily gamma-ray log baselines coupled with neutron-density crossovers. Eleven lithofacies were recognised from core samples. The pore reduction factor was calculated, and corrected for overburden conditions. Observing core porosity distribution for all wells, well F-AH4 displayed the highest recorded porosity, whereas well F-AH1 measured the lowest recorded porosity. Low porosity values have been attributed to mud and silt lamination influence as well as calcite overgrowths. The core permeability distribution over all the studied wells ranged between 0.001 mD and 2767 mD. Oil, water, and gas, were recorded within cored sections of the wells. Average oil saturations of 3 %, 1.1 %, and 0.2 % were discovered in wells F-AH1, F-AH2, and F-AH4. Wells F-AH1 to F-AR2 each had average gas saturations of 61 %, 57 %, 27 %, and 56 % respectively; average core water saturations of 36 %, 42 %, 27 %, and 44 % were recorded per well.
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Mosavel, Haajierah. "Hydrocarbon potential of the Prince Albert Formation, Ecca Group in the main Karoo Basin, South Africa." University of the Western Cape, 2020. http://hdl.handle.net/11394/8342.
Повний текст джерелаАнотація:
Philosophiae Doctor - PhDThis thesis focusses on the hydrocarbon potential of the Prince Albert Formation in terms of its shale gas potential. Unconventional gas production from hydrocarbon-rich shale formations, known as “shale gas”, is one of the most rapidly expanding trends in onshore oil and gas exploration and exploitation today. In South Africa, the southern portion of the main Karoo Basin is potentially favourable for shale gas accumulation and may become a game changer in the energy production regime of the country. The Prince Albert Formation was selected for research, since previous studies in South Africa have focused on shale from the Whitehill Formation, which together with the underlying Prince Albert Formation, occur within the lower Ecca Group in the main Karoo Basin.
2023-08-16
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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.
Повний текст джерелаАнотація:
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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Draper, Paul Christopher. "Secondary migration fairways and hydrocarbon potential of the Southern Enderby Terrace, Northern Carnarvon Basin, Western Australia /." Title page, contents and abstract only, 1995. http://web4.library.adelaide.edu.au/theses/09SB/09sbd766.pdf.
Повний текст джерелаАнотація:
Thesis (B. Sc.(Hons.))--University of Adelaide, National Centre for Petroleum Geology and Geophysics, 1995.Two folded maps in pocket inside back cover. Includes bibliographical references (leaves 130-135).
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Gray, Jayne L. "Aspects of hydrocarbon migration from a Permian coal seam in the southwest Cooper Basin, South Australia /." Title page, table of contents and abstract only, 1998. http://web4.library.adelaide.edu.au/theses/09SB/09sbg779.pdf.
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London, Jeremy Taylor. "Geologic Factors Affecting Hydrocarbon Occurrence in Paleovalleys of the Mississippian-Pennsylvanian Unconformity in the Illinois Basin." TopSCHOLAR®, 2014. http://digitalcommons.wku.edu/theses/1355.
Повний текст джерелаАнотація:
Paleovalleys associated with the Mississippian-Pennsylvanian unconformity have been identified as potential targets for hydrocarbon exploration in the Illinois Basin. Though there is little literature addressing the geologic factors controlling hydrocarbon accumulation in sub-Pennsylvanian paleovalleys basin-wide, much work has been done to identify the Mississippian-Pennsylvanian unconformity, characterize the Chesterian and basal Pennsylvanian lithology, map the sub-Pennsylvanian paleogeology and delineate the pre-Pennsylvanian paleovalleys in the Illinois Basin. This study uses Geographic Information Systems (GIS) to determine the geologic factors controlling the distribution of hydrocarbon-bearing sub-Pennsylvanian paleovalley fill in the Illinois Basin. A methodology was developed to identify densely-drilled areas without associated petroleum occurrence in basal Pennsylvanian paleovalley fill. Kernel density estimation was used to approximate drilling activity throughout the basin and identify “hotspots” of high well density. Pennsylvanian oil and gas fields were compared to the hotspots to identify which areas were most likely unrelated to Pennsylvanian production. Those hotspots were then compared to areas with known hydrocarbon accumulations in sub-Pennsylvanian paleovalleys to determine what varies geologically amongst these locations. Geologic differences provided insight regarding the spatial distribution of hydrocarbon-bearing sub-Pennsylvanian paleovalleys in the Illinois Basin. It was found that the distribution of hydrocarbon-bearing paleovalleys in the Illinois Basin follows structural features and faults. In the structurally dominated portions of the Illinois Basin, especially in eastern Illinois along the La Salle Anticlinal Belt, hydrocarbons migrate into paleovalleys from underlying hydrocarbon-rich sub- Pennsylvanian paleogeology. Along the fault-dominated areas, such as the Wabash, Rough Creek and Pennyrile Fault Zones, migration occurs upwards along faults from deeper sources. Cross sections were made to gain a better understanding of the paleovalley reservoir and to assess the utility of using all the data collected in this study to locate paleovalley reservoirs. The Main Consolidated Field in Crawford County, Illinois, was chosen as the best site for subsurface mapping due to its high well density, associated Pennsylvanian production, and locally incised productive Chesterian strata. Four cross sections revealed a complex paleovalley reservoir with many potential pay zones. The methodology used to locate this paleovalley reservoir can be applied to other potential sites within the Illinois Basin and to other basins as well.
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Lasisi, Ayodele Oluwatoyin. "Pore pressure prediction and direct hydrocarbon indicator: insight from the southern pletmos basin, offshore South Africa." Thesis, University of the Western Cape, 2014. http://hdl.handle.net/11394/4255.
Повний текст джерелаАнотація:
>Magister Scientiae - MScAn accurate prediction of pore pressure is an essential in reducing the risk involved in a well or field life cycle. This has formed an integral part of routine work for exploration, development and exploitation team in the oil and gas industries. Several factors such as sediment compaction, overburden, lithology characteristic, hydrocarbon pressure and capillary entry pressure contribute significantly to the cause of overpressure. Hence, understanding the dynamics associated with the above factors will certainly reduce the risk involved in drilling and production. This study examined three deep water drilled wells GA-W1, GA-N1, and GA-AA1 of lower cretaceous Hauterivian to early Aptian age between 112 to 117.5 (MA) Southern Pletmos sub-basin, Bredasdorp basin offshore South Africa. The study aimed to determine the pore pressure prediction of the reservoir formation of the wells. Eaton’s resistivity and Sonic method are adopted using depth dependent normal compaction trendline (NCT) has been carried out for this study. The variation of the overburden gradient (OBG), the Effective stress, Fracture gradient (FG), Fracture pressure (FP), Pore pressure gradient (PPG) and the predicted pore pressure (PPP) have been studied for the selected wells. The overburden changes slightly as follow: 2.09g/cm3, 2.23g/cm3 and 2.24g/cm3 across the selected intervals depth of wells. The predicted pore pressure calculated for the intervals depth of selected wells GA-W1, GA-N1 and GA-AA1 also varies slightly down the depths as follow: 3,405 psi, 4,110 psi, 5,062 psi respectively. The overpressure zone and normal pressure zone were encountered in well GA-W1, while a normal pressure zone was experienced in both well GA-N1 and GA-AA1. In addition, the direct hydrocarbon indicator (DHI) was carried out by method of post-stack amplitude analysis seismic reflectors surface which was used to determine the hydrocarbon prospect zone of the wells from the seismic section. It majorly indicate the zones of thick hydrocarbon sand from the amplitude extraction grid map horizon reflectors at 13AT1 & 8AT1 and 8AT1 & 1AT1 of the well GA-W1, GA-N1 and GA-AA1 respectively. These are suggested to be the hydrocarbon prospect locations (wet-gas to Oil prone source) on the seismic section with fault trending along the horizons. No bright spot, flat spot and dim spot was observed except for some related pitfalls anomalies
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Ward, Emily M. Geraghty. "Development of the Rocky Mountain foreland basin combined structural, mineralogical, and geochemical analysis of basin evolution, Rocky Mountain thrust front, northwest Montana /." CONNECT TO THIS TITLE ONLINE, 2007. http://etd.lib.umt.edu/theses/available/etd-09262007-094800/.
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Mohammed, Saeed. "Geochemical evaluation of source rock potential and characterization of hydrocarbon occurrences in the Eastern Dahomey Basin, Nigeria." University of Western Cape, 2020. http://hdl.handle.net/11394/7929.
Повний текст джерелаАнотація:
Philosophiae Doctor - PhDNigeria is endowed with significant oil sand and heavy oil reserves. These reserves are found within the Cretaceous Afowo Formation in the Eastern Dahomey Basin. The petroleum systems and quality of these reserves are poorly understood. Harnessing these resources necessitate comprehensive deposit evaluation and characterization.
2023
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Haselwood, Richard Franklin. "Aspects of the hydrocarbon potential of the Lockrose to Tamrookun section of the Clarence-Moreton Basin, Queensland." Thesis, Queensland University of Technology, 2003.
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Gaiennie, Edward Wilson Jr. "An Investigation into Secondary Migration of Hydrocarbons in the San Joaquin Basin Near Fresno, California." Thesis, University of Louisiana at Lafayette, 2019. http://pqdtopen.proquest.com/#viewpdf?dispub=10815005.
Повний текст джерелаАнотація:
Prolific amounts of oil and gas have been produced from the San Joaquin Basin in many different oil and gas fields. In many cases, the petroleum system is easily identifiable, and the path hydrocarbons take from source area to trap are known. This study aims to identify secondary migration pathways of hydrocarbons from the source to the trap in an oil field near Fresno, California, where the source is about 35 miles from the trap. To create an accurate subsurface interpretation of the study area, 3D seismic data and more than 300 well logs were used. From subsurface structure maps, net sand maps, an Allan profile, and regional research, it was found that there are two possible migration scenarios that reasonably describe the secondary migration of hydrocarbons into the study area. Six normal faults within the field play large roles as seals and/or migration pathways, and to better understand hydrocarbon migration in the study area, further work must be done on the sealing/leaking behavior of the faults within the field.