TA的每日心情 | 奋斗 2015-9-9 15:52 |
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Success in shale-gas resource systems has renewed interest in efforts to attempt
to produce oil from organic-rich mudstones or juxtaposed lithofacies
as reservoir rocks. The economic value of petroleum liquids is greater than
that of natural gas; thus, efforts to move from gas into more liquid-rich and blackoil
areas have been another United States exploration and production paradigm
shift since about 2008.
Shale-oil resource systems are organic-rich mudstones that have generated
oil that is stored in the organic-rich mudstone intervals or migrated into juxtaposed,
continuous organic-lean intervals. This definition includes not only the
organic-rich mudstone or shale itself, but also those systems with juxtaposed
(overlying, underlying, or interbedded) organic-lean rocks, such as carbonates.
Systems such as the Bakken and Niobrara formations with juxtaposed organic-lean
units to organic-rich source rocks are considered part of the sameshale-oil resource
system. Thus, these systems may include primary and secondary migrated oil. Oil
that has undergone tertiary migration to nonjuxtaposed reservoirs is part of a
petroleum system, but not a shale-oil resource system.
A very basic approach for classifying shale-oil resource systems by their
dominant organic and lithologic characteristics is (1) organic-rich mudstones
with predominantly healed fractures, if any; (2) organic-richmudstones with open
fractures; and (3) hybrid systems with a combination of juxtaposed organic-rich
and organic-lean intervals. Some overlap certainly exists among these systems,
but this basic classification scheme does provide an indication of the expected
range of production success given current knowledge and technologies for
inducing these systems to flow petroleum.
Potential producibility of oil is indicated by a simple geochemical ratio that
normalizes oil content to total organic carbon (TOC) referred to as the oil saturation
index (OSI). The OSI is simply an oil crossover effect described as when
petroleum content exceeds more than 100 mg oil/g TOC. Absolute oil yields do not provide an indication of this potential for production as oil content tends to
increase as a natural part of thermal maturation. Furthermore, a sorption effect
exists whereby oil is retained by organic carbon. It is postulated that as much as 70
to 80 mg oil/g TOC is retained by organic-rich source rocks, thereby limiting producibility
in the absence of open fractures or enhanced permeability. At higher
maturity, of course, this oil is cracked to gas, explaining the high volume of gas in
various shale-gas resource systems. Organic-lean rocks, such as carbonates, sands,
or silts, may have much lower oil contents, but only limited retention of oil as
these rocks havemuch lower sorptive capacity. The presence of organic-lean facies or
occurrence of an open-fracture network reducethe importanceof thesorptioneffect.
The oil crossover effect is demonstrated by examples from organic-rich but
fractured Monterey, Bazhenov, and Bakken shales; organic-rich but ultra-lowpermeability
mudstone systems, such as the Barnett and Tuscaloosa shales; and
hybrid systems, such as the Bakken Formation, Niobrara Shale, and Eagle Ford
Shale, as well as Toarcian Shale and carbonates in the Paris Basin. |
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