Academic literature on the topic 'Structural traps (Petroleum geology)'

ABSTRACT The purpose of this thesis project work is to build reservoir models (structural, facies and Petrophysical property models) of the different reservoir surfaces using integrated data sets (seismic, wells, fault sticks, eclipse models, horizon surfaces) of the Norne field which is located in blocks 6608/10 and 6508/1 in the southern part of the Nordland II area. Different visualizations techniques, volume rendering and seismic attributes were applied to aid the seismic interpretation and to provide detailed evaluation/integration of the data. 3D seismic interpretation for the whole seismic volume within the reservoir section was done manually with controlled input surfaces/reflectors of the Top horizons of the Not and Åre Formations. Fault and surfaces interpretation of the reservoir were generated as key inputs in the modeling process The structural 3D grid skeleton and models were generated with critical inputs of the manually interpreted faults/horizons, using different qualitative/quantitative templates in Petrel. This was followed by well interpretation and upscaling to provide discrete facies which are needed in populating the structural models of each of the reservoir surfaces. A probabilistic facies model was done to capture the proportion of the spatial dimensions of each discrete facies in the model frame. The initiation of this study involves quantitative data quality controls and management of inputs files into the Petrel window, qualitative control involves transferring geologic licenses/understanding to the various interpretations in the visualization schemes, seismic interpretation and reservoir modeling templates. The combination of different data type and idea (volumes, wells, top surfaces, and fault sticks) types means that the user must have a multivariate understanding (Geologic, Geophysical, Petrophysical, Geostastistic, Geo-Modeling and Reservoir Engineering) in other to integrate the data sets and deliver the models. Eleven wells were used in reference to the Top surface of the Not, Åre Top surfaces and Statoil Reference report of the field, to deliver and control the seismic interpretation. A wedge shape structure was observed in the reservoir section. Typically, minor and major faults were interpreted as forming compartments in the reservoir, which were interpreted across the different lines. The structural framework in the field was largely defined by the Norne Horst and associated faults, with the erosional surface of the BCU with internal sub unconformities observed. The property facies model of the reservoir surfaces (Garn, Ile, Tofte, and TIlje) suggest that the Norne Horst and sub relief structures are mainly sand rich, which provides additional prospect indicators in exploring the field

The Statfjord Formation (Rhaetian-Sinemurian) produces from six fields across the North Sea, but no discoveries have yet been made in the 12 exploration wells across the Oseberg South Field. The field has undergone two major periods of rifting in the Permian-Triassic and from the mid-Jurassic to Early Cretaceous. The Statfjord Formation was deposited during the Permian-Triassic post-rift period, but its tectonic influence on the paleogeography of the formation is not well understood. An isopach map produced from seismic interpretation and RMS modelling of the Statfjord Formation showed a westward thickening trend towards the present-day Viking Graben. This study presents results obtained using new, high-quality OBC seismic data that has allowed for faults throughout the field to be mapped in great detail. Supported by stratigraphic correlations and biostratigraphy, the mapping has showed that most faults can be assigned to either of the main rifting phases or their associated post-rift subsidence histories. Large, east-dipping faults are believed to have originated during the Permo-Triassic rifting, with evidence of movement into the Cretaceous. Large thickness increases of the formation over the westward dipping Oseberg and Brage Faults, as well as syn-rift sediments within some grabens in the J structure indicate movements of these faults during deposition. Biostratigraphic data show that the lowermost part of the Statfjord Formation was approximately the same thickness across the field until the Late Triassic, constraining the initiation of the Oseberg and Brage Faults to the Early Jurassic. Interpretations from timelines correlated within the Statfjord Formation suggest that the rate of subsidence along different faults was not consistent through time. Thickness changes along strike of the fault indicate that the movement along the fault was diachronous. This study aims to show that major fault activity influenced the deposition, and possibly preservation potential of sediment in the Statfjord Formation. The second phase of rifting is believed to have initiated many of the faults within the field, as well as reactivated the Oseberg and Brage Faults. Additional NW-SE faults in the Omega structure show no evidence of syn-rift sediments at the Statfjord Formation level, suggesting a mid-Jurassic post-rift origin. Similarly oriented faults were seen in the C structure, however, the presence of syn-rift sediments was difficult to ascertain, and no conclusions about the timing of initiation were made.

The North Sea basin is one of the best-studied areas in the world with respect to thestructural and sedimentary architecture of rift zones. The Base Cretaceous Unconformity,which defines a mappable horizon at the transition from synrift to postrift sequencesassociated with the Jurassic–Cretaceous rift, is well known as a reference marker for bothseismic and well log interpretations and covers most of the basin. This unconformity isinterpreted at the locations of the Øygarden Fault Zone, the Troll Fault Block, the NorthViking Graben, the Tampen Spur, the Snorre Fault Block, the Sogn Graben and the HordaPlatform. The complexities of the unconformity have been established and vary with thestructural and geographical position within the basin. However, as the Base CretaceousUnconformity covers most of the northern North Sea, its structural time map, is used to derivethe picture of post-structural framework of a rift basin and to locate essential structures in thedeeper sections.Three main reflectors (Pre-Jurassic 1, Pre-Jurassic 2 and Top seismic basement)located beneath the Base Cretaceous Unconformity on the Horda Platform, and have beeninterpreted using 2D seismic reflection data. These three reflectors have been studied in orderto investigate in detail the displacement gradients and possible linkage of the early faultsystem under the Horda Platform, and to evaluate their effect on the large-scale sedimentarchitecture. A main reason to work on the structures under the Horda Platform is due to thefact that these structures are believed to have existed already in the early stages of thenorthern North Sea basin development.The extensional normal fault systems of both the Permo-Triassic and the Late Jurassicrifts are considered a key control on the geological structures and sedimentary architecture ofthe region as presently seen. The basin evolution related Permo-Triassic rifting is mostpronounced on the eastern part of the Horda platform where its synrift geometry is obviouslyseen with the huge segment length and largest uplift explainable by a flexural stretchingmodel. The rift axis is transferred to position at base of the Viking graben during the Late-Jurassic rifting with the smaller magnitude of extension than the Permo-Triassic as clearlyseen by the less thickness of the synrift geometry. However, the structural evolution of normalfaults and the basin architecture under the Horda Platform is particularly affected by thecomplex interaction of fault linkage, fault propagation, fault growth, and death of faultthrough times from the early stage to the final stage of the basin development. Apart from theeffects of major tectonic controls, additionally, non-tectonic parameters, such as climate, seaor lake level changes, and differences in amount and type of sediment supply, should be takeninto account to influence the stratigraphic and sedimentation patterns in the basin.

The Berea Sandstone is a Late Devonian, tight oil and gas reservoir that intertongues with the Bedford Shale in eastern Kentucky. In order to evaluate the Bedford-Berea interval in the subsurface, 555 well logs from the Kentucky Geological Survey’s oil and gas database were used to construct structure maps, isopach maps, and cross sections of the interval and its possible hydrocarbon source rocks. Gamma-ray logs were compared to known cores in order to separate Bedford from Berea lithologies. Maps and cross sections were compared to known basement structures to evaluate possible structural influences on the interval. The Bedford-Berea interval is thickest along a north-south elongate trend which extends from Lewis to Pike Counties and cuts across basement structures. Along this trend, the interval is thickest and the percentage of Berea lithologies is greatest on known basement highs. The interval is thinnest and dominated by Bedford shales above structural lows and west of the main trend. Several wells are also reported in which the Bedford-Berea thickens on the down-thrown side of major faults. Also, in northeastern Kentucky, where the Berea is thickest, possible submarine channel facies are identified which cut into the underlying Cleveland Shale near the Waverly Arch.

Mapping at 1:25 000 scale on the central Graham Island has shown that Cretaceous strata are more widely distributed than previously known. This study examines the stratigraphy and structural geology of the Cretaceous rock sequence, and also addresses the petroleum potential of these units. At the base is the Cretaceous sandstone unit. This unit is divided into three lithofacies. The massive sandstone lithofacies is a coarse grained, dark green to greenish black, massive sandstone. Parts of this lithofacies contains up to 50 % glauconite. The grey sandstone lithofacies is finer grained and has better defined bedding than the massive sandstone. It is frequently found with interlayered sandstone, siltstone, and shale. The third sandstone lithofacies is characterized by pervasive bioturbation. All three lithofacies are texturally immature, contain angular quartz and feldspar, and are rich in chlorite clay. The Cretaceous sandstone unit is interpreted as a transgressive sequence deposited on a storm dominated shelf. Conformably overlying the sandstones are the massive friable shale and silty shale of the Cretaceous shale unit. Intervals with increased input of storm generated sandstone layers are found throughout the unit. Spherical and elliptical calcareous concretions up to over 1 m across are common. The Cretaceous shale unit represent a continuation of marine transgression with deepening of the sedimentary basin. Turbidites forming the Skidegate Formation are interbedded with the upper part of the shale unit. This formation consists of interbedded shale, siltstone, and fine grained sandstone. Sedimentary structures are often well developed on bedding surfaces. The rocks of this unit are distal turbidites and levee deposits of a submarine fan. Coarse clastic rocks of the Honna Formation are interbedded with the Skidegate Formation. This formation is dominated by pebbly conglomerates and coarse grained sandstones. The clast material in the conglomerate lithofacies is mainly derived from units present on the islands. The sandstone lithofacies consists of indurated, bluish, medium- to coarse-grained sandstone. This formation is richer in quartz and biotite than any other Cretaceous sandstones of the central Graham Island. The Honna and Skidegate formations are the result of deposition from a submarine fan system that was initiated in Late Cretaceous time. Deposition of shale continued after the deposition of the submarine fan-related formations terminated. The Cretaceous rock sequence is overlain by Tertiary volcanic and sedimentary rocks. Volcanic rocks occur throughout the area, and sediments of the Skonun Formation are exposed in north. Three major periods of deformation are recorded in the Cretaceous units. The first event was a Late Cretaceous to Early Tertiary northeast directed compression, resulting in northwest trending folds and thrust faults. The deformation was highly localized to areas were weakness zones existed in the older basement rocks. Two periods of Tertiary block faulting activity are recognized. The first resulted in northwest-trending faults, parallel to older structures. Later Tertiary block faulting developed northeast trending faults, which are the youngest macroscopic structures in the area. The Cretaceous rock sequence does not contain any promising hydrocarbon source or reservoir rocks. The TOC, S1, and S2 values from Rock-Eval® pyrolysis are low for all units, and the organic material present is mostly gas prone. Visual porosity is generally poor, as a result of chlorite pore-filling clay and calcite cement.<br>Science, Faculty of<br>Earth, Ocean and Atmospheric Sciences, Department of<br>Graduate

Hydraulic connectivity for the Tiber field and 17 other Wilcox penetrations in Keathley Canyon (KC) and 5 fields in Walker Ridge (WR) protraction areas was assessed. All five chronostratigraphic Wilcox units are not in vertical communication across both protraction areas. Four of these units are in lateral communication across Tiber field except where faults isolate portions of the structure. Five “areas of connectivity,” where two or more fields are in communication, were found in KC. The fields in WR show no evidence of connectivity despite a relatively simpler structural environment than KC. I propose that the wells in WR are isolated due to a combination of diagenetic cementation and increased vertical effective stress acting to decrease permeability between structures. I also attempted to assess the possibility of hydrodynamic flow in the primary basin encompassing Tiber by geophysically identifying the field’s oil water contact and determining its orientation. This was unsuccessful.

Made available in DSpace on 2014-06-11T19:26:14Z (GMT). No. of bitstreams: 0 Previous issue date: 2012-04-20Bitstream added on 2014-06-13T18:47:38Z : No. of bitstreams: 1 benvenutti_cf_me_rcla.pdf: 5702564 bytes, checksum: 3468aeafad128f8380c10b5ae674509f (MD5)<br>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...<br>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)

Resumo: 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... (Resumo completo, clicar acesso eletrônico abaixo)<br>Abstract: 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)<br>Orientador: Nelson Angeli<br>Coorientador: Maria Gabriela C. Vincetelli<br>Banca: George Luiz Luvizotto<br>Banca: Adilson Viana Soares Júnior<br>Mestre