Environmental Engineering Reference
In-Depth Information
temperature and pressure, temperatures of 110-120 1C generally being re-
quired to generate oil and 130-150 1Cforgasgeneration,
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occurring at
depths of around 4 km and greater than 5-6 km, respectively, in areas with
''typical'' basinal geothermal gradients of 30-35 1Ckm
1
. Expulsion of gen-
erated hydrocarbons, oil through light oil, condensate and wet gas to ultim-
ately dry gas, is generally considered to be consequence of the generation
process but is not well understood and appears to require a minimum kerogen
contentof2.5-3wt%TOCforakerogen'network'todevelop.
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This is believed
to allow the hydrocarbons to escape the source rock via a potentially hydro-
carbon-wet matrix to an adjacent permeable carrier bed where migration to
charge a conventional reservoir can occur. This model suggests that the par-
allel, generally water-wet mineral matrix of the shale source rock may not be
involved in the expulsion process, with implications for their potential later
development as shale-gas reservoirs. Prior to the widespread development of
shale resources, the expulsion of hydrocarbons from the source rock was
generally believed to be ecient, values of 60-90% being quoted.
9
However, the
large volume of shale gas present in oil-source rocks that have been matured
into the gas-window indicates that these values are probably an over-estimate.
The oil and gas reservoired in shales has been demonstrated to
represent hydrocarbons not expelled from the source during hydrocarbon
generation, with up to a third of generated products being retained.
9
In
particular, oil-prone kerogen-rich shales, such as the Barnett, Marcellus,
Fayetteville, Haynesville and Eagle Ford Shale formations, are the richest,
most prolific shale-gas reservoirs. This can be explained as due to the
thermal cracking of bitumens formed as a by-product of oil-generation as
well as unexpelled oil remaining trapped in shales by later maturation in the
gas-window. This results in the initial generation of light oils and conden-
sates followed by liquids-rich wet gas, with the ultimate generation of large
volumes of dry gas continuing through to high levels of maturation (VR of 3-
4% Ro). Continued cracking of the residual kerogen components remaining
in the shale post oil-generation provide a further source of gas and appear to
be critical in providing a considerable proportion of the porosity within the
shale. Clearly a proportion of these later-stage maturation products (con-
densates and dry gas) are expelled to conventional reservoirs, but the prolific
shale gas reservoirs show that much remains trapped in the source rock.
3.2 Porosity
Determination of porosity in shales requires several techniques to define the
parameter at all scales,
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based on either ''traditional'' core plugs or on cru-
shed and sieved core as typified by standardised methodology developed by
the US Gas Research Institute.
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On core plugs, mercury porosimetry can be
used to characterise pores down to around 5 nm, while smaller pores down to
0.3 nm diameter can be measured by low pressure N
2
and CO
2
sorption, total
porosity determination requiring He porosimetry (see Figure 7).
Despite considerable variation in composition, depositional setting and
compaction/maturation history, pore types within shale reservoirs fall into
