Exploration & Development in Southern Caribbean Frontier Basins - Presentation Proposal Form
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We have an unprecedented ability to realistically depict the spatial distributions of lithofacies in the subsurface thanks to developments in sequence stratigraphy, sedimentology, structural geology, geostatistics, and geophysics. As important as these developments have been, however, they in themselves have a limited ability to accurately predict rock properties–particularly in regions with high thermal exposures and restricted well control. We are developing a next-generation modeling platform that rigorously simulates processes in 3D at the grain scale. This 3D approach has the potential to provide unique predictive models of pore network geometries and grain contact properties for rocks in undrilled areas.
Reservoir characterization is an exercise in constraining uncertainty that arises from sparse sampling of the subsurface by widely spaced
wells at lengthscales below seismic resolution. Outcrop analogs are an
invaluable complement to well and seismic data in this context, because they
provide qualitative concepts and quantitative spatial data to guide
interpretations of lithology distribution in inter-well volumes. However,
analog-driven interpretations of reservoir architecture are not straightforward
to compare with dynamic data that describe fluid flow during production – the
acid test of any interpretation of reservoir geology. The value of outcrop
reservoir analogs is most fully realized when they are used to construct
outcrop-based reservoir models that enable explicit predictions of flow
patterns in a form that can be compared with routine reservoir-monitoring data.
I would like to suggest that far too much of the technical work purporting to guide exploration for petroleum is trivial, redundant and has little of use to offer toward finding new oil and gas accumulations. All geology is interesting; some geologic work is novel; damn little of the work we see is useful in finding new oil and gas fields!
A crucial aspect of these fluid inclusions… is that they endure in the geologic record although the parent fluids move on. As a result, a given sample contains the fluid history of the area. In other words, despite being microscopic they’re jam-packed with information.
Using diverse geologic and geophysical data from recent exploration and development, and experimental results of analysis of gas content, gas capacity, and gas composition, this article discusses how geologic, structural, and hydrological factors determine the heterogeneous distribution of gas in the Weibei coalbed methane (CBM) field.
The coal rank of the Pennsylvanian no. 5 coal seam is mainly low-volatile bituminous and semianthracite. The total gas content is 2.69 to 16.15 m3/t (95.00–570.33 scf/t), and gas saturation is 26.0% to 93.2%. Burial coalification followed by tectonically driven hydrothermal activity controls not only thermal maturity, but also the quality and quantity of thermogenic gas generated from the coal.
Gas composition indicates that the CBM is dry and of dominantly thermogenic origin. The thermogenic gases have been altered by fractionation that may be related to subsurface water movement in the southern part of the study area.
Three gas accumulation models are identified: (1) gas diffusion and long-distance migration of thermogenic gases to no-flow boundaries for sorption and minor conventional trapping, (2) hydrodynamic trapping of gas in structural lows, and (3) gas loss by hydrodynamic flushing. The first two models are applicable for the formation of two CBM enrichment areas in blocks B3 and B4, whereas the last model explains extremely low gas content and gas saturation in block B5. The variable gas content, saturation, and accumulation characteristics are mainly controlled by these gas accumulation models.
West Edmond field, located in central Oklahoma, is one of the largest oil accumulations in the Silurian–Devonian Hunton Group in this part of the Anadarko Basin. Production from all stratigraphic units in the field exceeds 170 million barrels of oil (MMBO) and 400 billion cubic feet of gas (BCFG), of which approximately 60 MMBO and 100 BCFG have been produced from the Hunton Group. Oil and gas are stratigraphically trapped to the east against the Nemaha uplift, to the north by a regional wedge-out of Hunton strata, and by intraformational diagenetic traps. Hunton Group reservoirs are the Bois d'Arc and Frisco Limestones, with lesser production from the Chimneyhill subgroup, Haragan Shale, and Henryhouse Formation.
Hunton Group cores from three wells that were examined petrographically indicate that complex diagenetic relations influence permeability and reservoir quality. Greatest porosity and permeability are associated with secondary dissolution in packstones and grainstones, forming hydrocarbon reservoirs. The overlying Devonian–Mississippian Woodford Shale is the major petroleum source rock for the Hunton Group in the field, based on one-dimensional and four-dimensional petroleum system models that were calibrated to well temperature and Woodford Shale vitrinite reflectance data. The source rock is marginally mature to mature for oil generation in the area of the West Edmond field, and migration of Woodford oil and gas from deeper parts of the basin also contributed to hydrocarbon accumulation.
The AAPG Latin America & Caribbean Region and the Colombian Association of Petroleum Geologists and Geophysicists (ACGGP) invite you join us for GTW Colombia 2020, a specialized workshop bringing leading scientists and industry practitioners to share best practices, exchange ideas and explore opportunities for future collaboration.
The 2-day workshop brings together technical experts and industry leaders from Colombia and throughout the Americas to take a multidisciplinary look at future opportunities for exploration and development of Southern Caribbean Frontier Basins.
The gas transport in organic-rich shales involves different length-scales, from organic and inorganic pores to macro- and macrofractures. In order to upscale the fluid transport from nanoscale (flow through nanopores) to larger scales (to micro- and macrofractures), multicontinuum methodology is planned to be used.
This e-symposium will focus on how surface geochemical surveys and Downhole Geochemical Imaging technologies can be utilized jointly to directly characterize the composition of hydrocarbons vertically through the prospect section.
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