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NARROW
GeoRef Subject
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all geography including DSDP/ODP Sites and Legs
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Asia
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Altai Mountains
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Gorny Altai (1)
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OSL Dating of the Sukor Earthquake-induced Rockslide in Gorny Altai: Paleoseismological and Paleogeographic Implications
Discussion on ‘A knowledge database of hanging-wall traps that are dependent on fault-rock seal’, Geological Society, London, Special Publications , 496, 209–222, https://doi.org/10.1144/SP496-2018-157
Discussion on ‘Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO 2 systems’, Petroleum Geoscience , 2020, https://doi.org/10.1144/petgeo2019-126
Validation and analysis procedures for juxtaposition and membrane fault seals in oil and gas exploration
Abstract We propose and validate methods for risk analysis of fault-bounded hydrocarbon traps in exploration. We concentrate on cross-fault leakage and consider lateral seals due to (1) juxtaposition and (2) high capillary-entry-pressure fault rock (membrane seal). We conclude that stochastic methods for fault seal analysis are essential, due to the large number of structural and stratigraphic parameters and the uncertainties. Central to the methods proposed is a Monte Carlo simulation which models geometrical and stratigraphic uncertainty. Multiple Allan maps (fault-parallel cross-sections) are produced and analysed for juxtaposition and shale gouge ratio (SGR). For validation, known discoveries with independently observed hydrocarbon–water contacts (IHWC) have been back-analysed. We present two case studies in this paper, and an additional 40 case studies are summarized (four public domain and 36 confidential case studies). The model outputs were compared with the IHWC. Juxtaposition analysis with no SGR contribution gives the smallest error. The inclusion of any fault rock seal mechanisms (such as SGR) matches or increases predicted hydrocarbon column heights compared to juxtaposition and gives larger errors. We conclude there is no reason to include fault rock membrane seals in exploration prospect risking.
Biodegradation, gas destruction and methane generation in deep subsurface petroleum reservoirs: an overview
Abstract Plate tectonics forms and destroys sedimentary basins, accumulating organic carbon and converting it into mobile petroleum which may be concentrated in reservoir traps in which, if temperatures are below 80°C, it may become biologically degraded (biodegraded). The biodegradation process produces altered, denser, heavy oils and methane as a primary product. Much of the world’s oil is biodegraded under anaerobic conditions, with methane being a major by-product of the action of the deep biosphere on petroleum when sulphate is not present as an oxidant. A review of the literature relating to destruction of wet gas and the systematics of methane generation during subsurface oil biodegradation concludes that large biodegrading oil fields may be major source systems of dry gas.
Abstract The Sunrise-Troubadour fields, containing between 10 and 16 tcf of retrograde gas condensate, are located in the Timor Sea, 450 km to the northwest of Darwin, Australia. The 80-m-thick, Middle Jurassic siliciclastic reservoir is entrapped in a fault-bounded structural closure that has 180 m of vertical relief and covers an area of 75 x 50 km. The volumetric significance of this field was identified through an intense late 1990s appraisal campaign. This paper presents the geoscientific results of this campaign and their implications for project evaluation and development planning. Reservoir quality, continuity, and connectivity are the essential subsurface determinants of the size of these accumulations. These parameters were primarily controlled by depositional environment. Overall, the reservoir succession is of moderate net to gross (approximately 30%); however, most of the gas is contained in two high net-togross sublayers. The latter main gas-bearing subintervals are interpreted to have been deposited during lowstand episodes, the lower unit being represented by an incised valley complex and the upper by attached, forced-regressive shoreface deposits. Deposition in this limited accommodation setting has resulted in lateral reservoir continuity and broad sheetlike stratigraphy. Lithologically, the reservoir comprises very fine- to coarse-grained quartzarenites and sublitharenites that are interbedded with variably brackish to open-marine shales. The whole succession displays an overall upward increase in marine influence. The main phase of faulting and trap formation occurred during the Quaternary. Detailed fault modeling indicates a low likelihood of compartmentalization in this extensive structural high. Variations in both hydrocarbon maturity and condensate yield across the field indicate nonequilibration of the recently emplaced hydrocarbons that have been derived from a mature (1.3-1.4 %Ro) Middle Jurassic marine kerogen source rock. Pressure analysis indicates a tilted gas-water contact that sits above a dynamic aquifer. Reservoir geologic data have been matched to seismic amplitude variation with offset (AVO ) effects to constrain depositional modeling via statistical inversion techniques. This has then been fully integrated with mapped and probabilistically modeled subseismic faults into dynamic reservoir simulations. The work flow involved the identification of key uncertainties and the detailed, focused evaluation of these parameters. This in turn provides confidence in reservoir volumes and behavior, despite widely spaced well data. Development planning is in progress, with commercial production planned for this decade.