Exploration & Development in Southern Caribbean Frontier Basins - Presentation Proposal Form
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A collection of abstracts from more than 50 academic papers regarding the controls and impacts of inorganic and organic diagenesis on mudstone hydrocarbon generation, reservoir properties and seal quality.
The assessment of the natural temporal
variability of source rock units is critical for the understanding of petroleum systems as changes in
mineral matrix, organic matter (OM) concentration,
and composition can significantly affect expulsion efficiency, primary and secondary
migration processes, hydrocarbon quality as well as oil source rock correlation. Already small-scaled fluctuations within sediment successions
can critically influence migration efficiency. High-resolution investigation of a well-preserved Lower Jurassic drill core (Toarcian Posidonia
Shale) revealed seven discrete and systematic intervals of deviating source rock quality. These were composed of homogenized,
marls of light grey color, opposed to laminated dark grey background sedimentation. Both lithotypes differentiate not only in mineral
composition, but particularly in OM content and quality. An average TOC content of app. 3.9 wt.% reached by the grey marl, is
faced by an
average TOC content of app. 7.8 wt.% measured for the laminated dark grey marls. Average
hydrogen index for grey non-laminated marls was
app. 550 mg HC/g TOC, whereas much higher source rock quality with 780 mg HC/g TOC was attained in the dark laminated marls.
lower OM concentration and inferior OM quality generates important domains for preferential migration of products, originated from the dark
grey layers, or hydrocarbon cluster in case of limited migration into adjacent reservoirs. To assess the potential for preferential intake of
hydrocarbons by the coarser-grained light marls and their qualification as migration avenues, artificial maturation experiments were performed
with both lithotypes. Hydrocarbon generation was simulated by hydrous pyrolysis in two successive temperature steps 330 °C and 360 °C,
covering an early maturity stage, as well as the end of the oil window. Both lithologies show striking differences, not only for the extract yield,
but also for the timing of generation. OM quality differences were reflected by variable n-alkane distributions and molecular maturity
parameters. High-resolution continuous data produced by non-destructive techniques allows to draw conclusions on i) source rock potential,
ii) expulsion and migration processes
and iii) on prediction of petroleum accumulation within the sediment succession. High-resolution
investigation in combination with artificial maturation experiments represent an easy-to-use tool in petroleum system analysis.
The San Joaquin Basin lies west of the Sierra Nevada Mountains and east of the San Andre
as Fault. Tens of kilometers of Mesozoic and
Cenozoic sediments, including deep-water organic-rich source rocks, deposited in a forearc setting, comprise the basin and have contributed to
a petroleum system that generates more than 70 percent of California
's daily oil production and includes three of the 10 largest oilfields in the
United States. Based on a comprehensive 3D petroleum systems model of the San Joaquin basin, published by the USGS in 2008, we further
refine the modeling to account for the unique depositional and tectonic history of the basin. Here, we compare various basal heat flow scenarios
to model hydrocarbon generation and calibrate the results to available temperature and vitrinite reflectance (Vr) data. We investigate two types
of crustal models: a McKenzie-type rift model, and a no-rift static crustal thickness model. Crustal stretching models calculate basal heat flow
resulting from stretching/thinning of mantle and crust during initial (syn-rift) and thermal (post-rift) subsidence. This method uses rock matrix
radiogenic heat production values. It does not account for transient effects resulting from burial and uplift of the basin fill. The static no-rift
model, alternatively, calculates the basal heat flow based on a stable or non-thinning crust and mantle over time. This method uses estimated
Uranium (U), Thorium (Th), and Potassium (K) concentrations within the rock material to then calculate the rock matrix heat production.
Unlike the rift model, it accounts for the transient effects
resulting from burial and uplift of the basin fill, which can have a considerable
additional effect on the basal heat flow. Given the low probability of crustal stretching as the starting point for basal heat flow in the San
Joaquin Basin and considering
the forearc nature of the basin as well as the strong concentration of U, K, and Th in the Sierran granites, we
focused on and refined the no-rift models. We manually account for the transitional nature of the San Joaquin basement from hot Sierran
on the east to cool Franciscan oceanic rocks on the west. Radiogenic heat production from solely continental crust results in
are too warm and cannot be calibrated to well temperature and Vr data. Solely oceanic models are too cool to match well data. ‘Combined
crust’ incorporates a seismically derived suture zone that allows for a transition from oceanic to granitic basement, while the ‘intermediate
crust’ mixes oceanic and continental radiogenic heat production. These models generate a good match to well data to the east and westward
through the transition zone. Additionally, we are able to calibrate to wells off of the Belridge and Lost Hills structures. On structure wells,
however, cannot be calibrated with a crustal conductive heat flow scenario and would require (local) elevated heat flows on the order of 20
2. This is not in agreement with the generally cooler underlying oceanic crust and suggests that there might be a different and/or
additional source of heat flow. Most likely, basin-scale hydrothermal groundwater flow, both along faults and up-structure, could account for
elevated Vr and temperature. Convective heat flow would be an additional overprint or enhancement to conductive basal heat flow.
The driving forces for conventional accumulations (structural or stratigraphic traps) are Forces of Buoyancy which are due to
densities of hydrocarbons and water. In contrast, the driving forces for unconventional tight accumulations are Forces of Expulsion which are
produced by high pressures. That is an enormous difference and creates unconventional petroleum systems that are characterized by very
different and distinctive characteristics. The Force of Expulsion pressures are created by the
significant increase in volume when any of the
three main kerogen types are converted to hydrocarbons. At those conversion times in the burial history, the rocks are already sufficiently tight
so the large volumes of generated hydrocarbons cannot efficiently escape through the existing tight pore system,
thus creating a permeability
bottleneck that produces an overpressured compartment over a large area corresponding to the proper thermal oil and gas maturities for that
basin. The forces initially created
in these source rocks can only go limited distances into adjacent tight reservoirs (clastics or carbonates)
above or below the source. The exact distance will vary depending on the pressure increase, matrix permeability, and fractures of that specific
tight reservoir system. In general, the distances are small, in the orders of 10s to 100s of feet for oil and larger for more mobile gas systems.
Those exact distance numbers are subject to ongoing investigations.
A plot of the pressure data versus elevation
for a given formation is critical in determining whether an accumulation is conventional or
unconventional. Conventional accumulations will have hydrocarbon columns of 10s to 100s of feet with the pressure in the hydrocarbons and
that in the water equal at the bottom of the accumulation (at the HC-water contact). In contrast, the unconventional accumulations will show
HC column heights of 1000s of feet with the pressure in the hydrocarbon phase and the water phase being the same at the top of the
accumulation (at the updip transition zone). Those significant differences are critical for understanding and differentiating these two play types.
Because the system is a pore throat bottleneck with very little or minimum lateral migration, the type of hydrocarbon
s are closely tied to the
thermal maturity required to generate those hydrocarbons. Thus the play concept begins with two important geochemical considerations: (1)
where are the source rocks and what are the kerogen types and organic richness (TOC), and (2
) where are they mature in the basin for oil,
condensate, and gas in the basin. These parameters will very quickly define the fairway for the play. Then one has to add the
information on the reservoirs themselves: composition (brittleness), thickness, and reservoir quality (matrix porosity and permeability). In
summary, these tight unconventional petroleum systems (1) are dynamic
and (2) create a regionally inverted petroleum system with water over
oil over condensate over gas for source rocks wit
h Type I or II kerogen types.
The Indian National Gas Hydrate Program Expedition 02 (NGHP-02) was conducted from 3-March-2015 to 28-July-2015 off the eastern coast of India. The primary goal of this expedition was the exploration and discovery of highly saturated gas hydrate occurrences in sand reservoirs that would be targets of future production testing.
The study of gas hydrates in nature has been ongoing for over 40 years. Significant strides have been made in our understanding of the occurrence, distribution, and characteristics of marine and permafrost associated gas hydrates.
This lecture presents the findings of recent international gas hydrate exploration efforts that are using new advanced technologies to identify and characterize the properties of gas hydrate prospects. Case studies from the Alaska North Slope, Gulf of Mexico, Japan and India demonstrate how standard oilfield technologies are helping to identify and evaluate gas hydrate accumulations.
It has been suggested that gas hydrates may represent an important future source of energy; however, much remains to be learned about their characteristics and occurrence in nature. This lecture reviews recent successes in exploration and production of natural gas from gas hydrate accumulations.
The Arctic Ocean occupies a unique tectonic setting as a small, confined ocean between two much larger oceans - the subducting Pacific margin and the opening North Atlantic. Unlike many of the world's oceans, evidence on both timing and geometry is poor, and major elements of the plate tectonic evolution are still "up for grabs". The Arctic has experienced significant plate motion from Cretaceous to present, and because of the ambiguities in the oceanic signature, resolving the most likely kinematic history is critical in understanding paleogeography and hence reservoir and source distribution. I will show a 3-stage kinematic model which, while not a unique solution, seems to best satisfy the known constraints.
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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