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- Volume 6, Issue 2, 2000
Petroleum Geoscience - Volume 6, Issue 2, 2000
Volume 6, Issue 2, 2000
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Developing and managing turbidite reservoirs – case histories and experiences: results of the 1998 EAGE/AAPG research conference
Authors Peter Dromgoole, Mike Bowman, Andrew Leonard, Paul Weimer and Roger M. SlattThis paper summarizes the results of a joint EAGE/AAPG research conference that was convened in Almeria, Spain in October 1998. The theme of the conference was how to better produce deep-water reservoirs based on lessons learned from the past 25 years. A repeated message at the conference was that there is more complexity than anticipated in turbidite reservoirs, contrary to the expectations of many geoscientists. Such complexity may go unnoticed during initial depletion, and only be observed during secondary injection of fluids. Early recognition of shale occurrences and geometries, bed continuity, and stratigraphic variations in net-to-gross ratios appear to be the main issues related to maximizing well performance.
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Closing the gap between theory and practice in seismic interpretation of small-scale faults
Authors Jonny Hesthammer and Jon Ottar HendenThe ability to map small-scale faults from seismic surveys depends upon resolution, noise content and acquisition/processing procedure. In addition, the geoscientist must possess a sound understanding of plausible geometries consistent with analyses of well data. The comparison of two seismic datasets from the Gullveig structure, northern North Sea, demonstrates that the lateral resolution of the data is strongly dependent on the signal-to-noise ratio. By combining a theoretical approach with statistics from well analyses, exemplified by data from the Gullfaks Field, it is possible to enhance our understanding of the limits of fault resolution on 3D seismic data.
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Experiments on clay smear formation along faults
Authors Susanne Sperrevik, Roald B. Færseth and Roy H. GabrielsenA ring shear apparatus was used to investigate the development of clay smear along faults in sand–clay sequences. Experiments were performed, using six different clay types, different stress conditions (σn=6–500 kPa) and different amounts of clay (4 and 12.5%). The development of clay smear seems to depend on the competence contrast between the clay and the surrounding sand. Clay, when it is less competent than sand, behaves in a ductile manner, resulting in the development of clay smears along the fault. Clay which is more competent than sand behaves in a brittle manner, resulting in the formation of angular fragments. Whether the clay is more or less competent than the sand is dependent on the stress conditions, the initial porosity of the sand and the mechanical properties of the clay. The results suggest that stress conditions allowing the sample to contract will result in the formation of fluid flow barriers, whereas dilation results in the formation of conduits.
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Evolution and hydrocarbon habitat of the South Turgay Basin, Kazakhstan
Authors B. A. Moseley and V. A. TsimmerThe South Turgay Basin is a Mesozoic intracontinental rift with a Lower Jurassic to Lower Cretaceous fill. It is underlain by a basement complex comprising Precambrian metamorphics and Palaeozoic carbonates and clastics, and was formed as a result of right lateral movement on the Karatau–Talasso–Fergana Fault. Four principal graben systems are found in the basin. These are the Ariskum, Akshabulak, Sarylan and Bozingen grabens. The graben fill is represented by up to 5 km of dominantly continental sediments, with lacustrine, alluvial and fluvial units, with a series of gross fining-upwards sequences in the Lower to Middle Jurassic (syn-rift) and Upper Jurassic to Lower Cretaceous (post-rift). Marginal marine conditions began to become established during the Apto-Albian with a marine transgression from the west. Tertiary regional uplift resulting from the India–Eurasia collision stripped off later deposits. Recoverable hydrocarbons in the order of 1 billion barrels of oil equivalent have been proven to date in the large Kumkol Field and a number of smaller pools.
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The relationship between the composition and rank of humic coals and their activation energy distributions for the generation of bulk petroleum
Authors H. I. Petersen and P. RosenbergActivation energy (E a) distributions and pre-exponential factors (A) of 27 humic coals of varying composition, rank, age and origin are discussed. The petrography and rank of the coals have been correlated to the distribution of E a and the Hydrogen Index (HI). The HI is positively correlated to vitrinitic and liptinitic constituents; in particular, the vitrinite maceral collotelinite has a strong influence on the HI. Inertinitic constituents have a negative effect on the HI. A higher value of the peak position of the E a distributions is mainly controlled by the thermal maturity and to a lesser extent by the proportion of collotelinite. A number of other vitrinitic components result in a lower E a peak position. The peak width of the E a distributions is broadened by high vitrinite reflectance values and higher proportions of collotelinite and the microlithotypes vitrite and vitrinertite. Liptinitic and inertinitic constituents, in particular the microlithotype clarodurite, narrow the peak width.
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Petrography and clay mineralogy of volcanoclastic sandstones in the Triassic Rewan Group, Bowen Basin, Australia
More LessThe sandstones of the Early Triassic non-marine Rewan Group in the southern Bowen Basin represent a potential reservoir for hydrocarbons. They are mainly lithic in nature, with a large proportion of volcanic rock fragments and contain quartz grains of variable size and an authigenic clay matrix. The results of petrographic analysis show a dual provenance basin-fill pattern (cratonic–volcanic). Reservoir qualities vary considerably, but are best developed in the Quartzose and Conglomerate Intervals where partial quartz cement retarded compaction and secondary porosity developed by dissolution of labile material and flushing of clay minerals. The presence of different clay minerals in pore networks may have a significant impact on petrophysical properties of the reservoir and hence affect reservoir productivity.
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The Miocene petroleum system of the Sava Depression, Croatia
Authors G. Baric, Z. Ivkovic and R. PericaThe Sava Depression, located on the southern margin of the Pannonian Basin, contains a number of small oil and gas fields. The depression is filled principally with Neogene sediments resting on Palaeozoic crystalline basement. Rifting occurred in Early to Middle Miocene times. Geochemical data imply that Middle to Upper Miocene pelites are good oil-prone source rocks. Most of the oil and oil–gas fields are situated at depths of 370 to 2300 m. Weathered basement rocks and Miocene conglomerates and sandstones are reservoir rocks and the fields are mostly structural and/or structural–stratigraphic traps. Oils from the fields correlate well with the identified source rock facies and maturity level and we propose short migration distances. Sava oil properties show variations in bulk and specific parameters that can be attributed to post-generative processes.
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Distribution pattern of hydrogen sulphide-bearing gas in the former Soviet Union
More LessH2S is an unwelcome accompaniment to natural hydrocarbon gas but, in sufficient volumes, it can provide an economic source of sulphur, termed a ‘gaseous sulphur’ accumulation. Such accumulations are an important component of the sulphur reserves of Russia and other countries. A comparative study of the distribution of economic gaseous sulphur accumulations, together with native sulphur deposits, in the Amu Dar’ya, Volga–Urals, North Caspian and other basins of the former Soviet Union and elsewhere shows that they occur only within large hydrocarbon basins and are restricted to thick and regionally persistent evaporite–carbonate successions. The lithological and geochemical controls and various types of sulphur paragenesis result in a zoned series of accumulations, from gaseous sulphur to sulphur-rich oils to native sulphur, which can be traced from the deep central regions of hydrocarbon-bearing basins with sulphate–evaporite successions towards the shallow basin margins.
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Use of 3D digital analogues as templates in reservoir modelling
Geological analogues may be used to rigorously interpret three-dimensional (3D) subsurface reservoir geometry by combining the capabilities of graphics workstations with digital outcrop data collection. Digital data from sedimentary environments and outcropping geological formations are interpreted in a 3D viewing environment to construct 3D templates of analogues for reservoir bodies. These 3D geometries and associated scaling parameters are then available to build 3D digital hypotheses concerning subsurface reservoir geometries.
Two examples serve to illustrate this approach. Data from a modern fluvial system in the USA are used to construct digital templates. Interpretation of this dataset enables the relationship between 3D external geometries of sedimentary units to be rigorously defined and related to internal sedimentary structures. The location of gas-filled reservoir compartments in the Carboniferous Bend Conglomerate reservoirs of the Boonsville Field in North Texas are then interpreted using such analogue-derived digital templates.
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Volumes & issues
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Volume 30 (2024)
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Volume 29 (2023)
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Volume 28 (2022)
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Volume 27 (2021)
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Volume 26 (2020)
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Volume 25 (2019)
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Volume 24 (2018)
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Volume 23 (2017)
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Volume 22 (2016)
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Volume 21 (2015)
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Volume 20 (2014)
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Volume 19 (2013)
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Volume 18 (2012)
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Volume 17 (2011)
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Volume 16 (2010)
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Volume 15 (2009)
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Volume 14 (2008)
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Volume 13 (2007)
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Volume 12 (2006)
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Volume 11 (2005)
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Volume 10 (2004)
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Volume 9 (2003)
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Volume 8 (2002)
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Volume 7 (2001)
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Volume 6 (2000)
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Volume 5 (1999)
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Volume 4 (1998)
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Volume 3 (1997)
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Volume 2 (1996)
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Volume 1 (1995)