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Abstract
Many currently producing shale-gas reservoirs are overmature oil-prone source
rocks. Through burial and heating these reservoirs evolve from
organic-matter-rich mud deposited in marine, lacustrine, or swamp environments.
Key characterization parameters are: total organic carbon (TOC), maturity level
(vitrinite reflectance), mineralogy, thickness, and organic matter type.
Hydrogento-carbon (HI) and oxygen-to-carbon (OI) ratios are used to classify
organic matter that ranges from oil-prone algal and herbaceous to gas-prone
woody/coaly material.
Although organic-matter-rich intervals can be hundreds of meters thick,
vertical variability in TOC is high (<1-3 meters) and is controlled by
stratigraphic and biotic factors. In general, the fundamental geologic building
block of shale-gas reservoirs is the parasequence, and commonly 10’s to 100’s
of parasequences comprise the organic-rich formation whose lateral continuity
can be estimated using techniques and models developed for source rocks.
Typical analysis techniques for shale-gas reservoir rocks include: TOC, X-ray
diffraction, adsorbed/canister gas, vitrinite reflectance, detailed core and
thin-section descriptions, porosity, permeability, fluid saturation, and
optical and electron microscopy. These sample-based results are combined with
full well-log suites, including high resolution density and resistivity logs
and borehole images, to fully characterize these formations. Porosity, fluid
saturation, and permeability derived from core can be tied to log response;
however, several studies have shown that the results obtained from different
core analysis laboratories can vary significantly, reflecting differences in
analytical technique, differences in definitions of fundamental rock and fluid
properties, or the millimeter-scale variability common in mudstones that make
it problematic to select multiple samples with identical attributes.
Porosity determination in shale-gas mudstones is complicated by very small pore
sizes and, thus, large surface area (and associated surface water); moreover,
smectitic clays that are commonly present in mud have interlayer water, but
this clay family tends to be minimized in high maturity formations due to
illitization. Finally, SEM images of ion-beam-milled samples reveal a separate
nanoporosity system contained within the organic matter, possibly comprising
>50% of the total porosity, and these pores may be hydrocarbon wet, at
least during most of the thermal maturation process. A full understanding of
the relation of porosity and gas
content will result in development of optimized processes for hydrocarbon
recovery in shale-gas reservoirs.
Introduction/Background
The term “unconventional reservoirs” covers a wide range of hydrocarbon-bearing
formations and reservoir types that generally do not produce economic rates of
hydrocarbons without stimulation. Common terms for such “unconventional”
reservoirs include: Tight-Gas Sandstones, Gas Hydrates, Oil Shale formations,
Heavy Oil Sandstones, and Shale Gas, among others. The focus of this paper is
to discuss the geological genesis and characterization of the class of
“unconventional” reservoirs commonly termed Shale Gas.
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