Page 240 - Petroleum Geology

area because the vitrinite reflectance is 0.9%”, and such statements may be
very misleading. The data can be acquired from a single well, so they must be
used positively to indicate areas of interest, not negatively to discard areas.
Very large volumes of oil, including some of the giant oil fields, are in sedi-
mentary rocks that are regarded as immature by vitrinite reflectance standards.
Palynologists had also noted that the colour of spores and pollen became
darker with increasing depth, and interpreted these changes as due to thermal
influences (Gutjahr, 1966). The same reservations apply to this index of
maturity as for vitrinite reflectance.

PRIMARY MIGRATION

We infer that petroleum source material is disseminated through the source
rock sensu strict0 and therefore petroleum generated from it is also dissemi-
nated. The question then arises: how does this move out of the source rock?
There are three possible processes that each have their adherents: mole-
cular solution, colloidal solution, and as a separate, immiscible phase, in the
pore water.
Solution in pore water is attractive because the initial dissemination is no
obstacle, and it is the process that requires least work. The difficulties with
this hypothesis are twofold. Some process must exist for the exsolution of
the petroleum; and the laboratory-measured solubilities appear to be too low
by at least an order of magnitude. We will take the latter point first.
Even allowing for some doubt about the actual solubilities of the various
hydrocarbons, we can reach an estimate of the solubility required in some
areas. Jones (1981, p. 105) took DOW’S (1974) data for the Bakken Shale in
the Williston basin, Wyoming, U.S.A., and showed that a solubility of at least
15,000 ppm was required to account for the known oil in place assuming
that the Bakken Shale compacted from 10 to 5% porosity during generation.
(There is no point in making the distinction between weight/weight and vol-
ume/volume in such estimates of solubility.) The maximum solubility of oil
was taken as 200 ppm (see Price, 1976, p. 220, fig. 7). Even if the compac-
tion range is extended to 25-575 during generation, the solubility required is
only reduced to 3000 ppm. No manipulation of these figures seems capable
of reducing the requirement to the observed order of magnitude of oil solu-
bility in water.
This argument, it will be noted, does not eliminate solution as a process -
even as an important process - but it does suggest that if the source rock
generates liquid petroleum, solution is unlikely to be the main, general process
of primary migration to commercial oil fields.
Bonham (1980), on the other hand, modelled fluid migration in a compact-
ing sedimentary basin and, applying it to a “representative” area of the US.
Gulf Coast, came to the conclusion that a solution process could account