Page 213 - Geology and Geochemistry of Oil and Gas

182 CLASSIFICATIONS OF OIL AND GAS ACCUMULATIONS

Often, there is some decrease in the oil and especially gas density in the clastic rocks
with increasing clay content. This statement may be erroneous, however, due to the
effect of relative permeability when fluids move from the reservoir into the wellbore.
Light and some heavy hydrocarbons dissolve in the reservoir edge water. De-
pending on the direction of groundwater movement, front and rear effects may occur
(see Chapter 4). One has to remember, however, that oil–water and gas–water tran-
sition zones may form in a more severe (high temperature and pressure) environment.
The composition of oil and gas may be affected by the presence of faults that may
be either fluid conductors or barriers. These properties, however, may change along
the fault and in time, i.e., different segments of the same fault may serve as either a
seal or a fluid conductor, which may change with time. The faults can give rise to the
mixing of fluids from different horizons, the penetration of chemically or bacterially
aggressive water into the accumulation, and a partial or complete loss of hydro-
carbons. That is why it is difficult to define clear patterns in the hydrocarbon ac-
cumulations in relation to faults. Levorsen (1954) noted that the accumulations are
most commonly formed at the hanging wall and only occur at the footwall of faults if
there is an additional anticlinal deformation there. As far as the reverse faults are
concerned, a somewhat uncertain inverse correlation was found to exist, i.e., the
accumulations are more frequently found at the footwall.
The time of fault formation may play a crucial role in the formation of hydrocarbon
accumulations. It is interesting to note the role of faults formed during catagenesis
(epigenesis) (sometimes the faults are of hydraulic origin). In the low-permeability
rocks such faults are not necessarily represented by a continuous surface but rather by
an intricate network of channels. The latter do not manifest the disruption of rock
integrity but rather accommodate the fluid breakthrough through the existing channel.
In this connection, Savchenko (1987) proposed two terms: the breakthrough pressure
and the pinch-out pressure (pressure necessary to close the channel).
Based on the experimental data, the hydraulic fracture pressure and, even more
so, the breakthrough pressure is always higher than the hydrostatic pressure and
lower than the total overburden pressure. On conducting hydraulic fracturing, it is
necessary to overcome the effective pressure and the fracturing strength pressure
(Young’s modulus, which is very low for the rocks). If the rock density is 2.5 g/cm 3
3
and the water density is 1 g/cm , the hydraulic fracturing pressure will start at about
1.5 times the hydrostatic pressure.
Breakthroughs and pinch-outs are natural valves controlling temperature and
pressure in a reservoir. When a fluid breaks through and leaves the reservoir, some
heat is removed thereby lowering the temperature. The entrance of the fluid into
another reservoir may create the temperature and/or pressure anomaly in that res-
ervoir. This is one of the reasons for the hydrocarbon accumulations to remain
within the estimated temperature and pressure range. The existence of reservoirs that
are not amenable to the natural hydraulic fracturing or breakthrough is theoretically
plausible. Accumulations with pressure equal to or temporarily even exceeding the
total overburden pressure (by the amount of tensile strength — Young’s modulus)
could have formed. This, however, is the domain of volcanology, and such accu-
mulations are yet to be discovered.