Page 179 - Petroleum Geology

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Geothermal gradients very widely, commonly between 25 and 40”C/km, so
the temperature in a typical reservoir at a depth of 2000 m will be between
65” and 95°C. The fluids and the solids are also at elevated pressures, depending
generally on the depth and the pressure gradients due to the weight of the
overlying materials. We shall consider the pressures in more detail later.
The accumulation is bounded above by a relatively fine-grained material
such as a mudstone - or, more precisely, by a material with small pores. The
criterion here is that the capillary injection pressure required for the oil or
gas to penetrate the cap rock is greater than that existing in the reservoir fluid.
The accumulation is usually bounded below by a material of small pores, and,
within the reservoir rock unit, by the oil/water or gaslwater contact below
which the pores are entirely saturated with water that is usually saline. This
interface between the petroleum and the water is horizontal or nearly hori-
zontal. The accumulation is sometimes bounded laterally by a fault which
may itself be a barrier to further migration on account of the fine-grained
fault gouge in the fault plane, or which may bring fine-grained material with
small pores into juxtaposition with the reservoir across the fault. Within the
reservoir pore spaces, both water and petroleum exist. Reservoir engineers
call this “connate” water. We shall examine this first.

Water saturation

When a properly constructed well produces from a virgin oil reservoir,
from a zone well away from the oil/water contact or gas/water contact, it
typically produces most of its ultimate yield without water. Towards the end
of its life, when the oillwater contact approaches the producing zone, the
water-cut typically increases and the total liquid production decreases until
the well is no longer economic.
If a core is cut in such a reservoir using oil-base mud, so that the connate
water is neither displaced nor contaminated, the water saturation (always
expressed as a proportion or percentage of the pore space) is found to be be-
tween 5 and 60% (rarely, even higher), with values between 15 and 40% com-
mon. There is no marked tendency towards lower saturations with increased
elevation above the oil/water contact except in a thin zone at the oillwater
contact (Fig. 8-1). This paradoxical result is of considerable interest to geol-
ogists as well as petroleum engineers.
Bruce and Welge (1947, p. 235, table 1) and Thornton andMarshall(1947,
p. 73, table 1) made measurements of water saturation in cores cut in an oil
reservoir using oil-base mud, and estimated the water saturation by simula-
tion, using a restored-state, capillary pressure method. In such restored-state
experiments it was found that the water saturation reached a figure that was
virtually independent of the capillary pressures. This is called the irreducible
water saturation. The correlation between the two sets of figures is statistically
highly significant, and Fig. 8-2 shows the data plotted as correlation lines over