Page 147 - Hydrocarbon Exploration and Production Second Edition

134 Reservoir Fluids

this point. The OBP is in fact balanced by a combination of the fluid pressure in the
pore space (FP) and the stress between the rock grains of the matrix (s g ).

OBP ¼ FP þ s g
At a given depth, the OBP remains constant (at a gradient of approximately
1 psi/ft), so that with production of the reservoir fluid, the fluid pressure decreases,
creating an increase in the grain-to-grain stress. This may result in the grains of rock
crushing closer together, providing a small amount of drive energy (compaction
drive) to the production. In extreme cases of pressure depletion in poorly compacted
rocks this can give rise to a reduction in the thickness of the reservoir, leading
ultimately to surface subsidence. This has been experienced in the Groningen gas
field in the Netherlands (approximately 1 m of subsidence), and more dramatically in
the Ekofisk Field in the Norwegian sector of the North Sea (around 6 m subsidence),
as mentioned in Section 6.1.3.
In a normal pressure regime, the pressure in a hydrocarbon accumulation is
determined by the pressure gradient of the overlying water (dP/dD) w , which ranges
from 0.435 psi/ft (10 kPa/m) for freshwater to around 0.5 psi/ft (11.5 kPa/m) for
salt-saturated brine. At any depth (D), the water pressure (P w ) can be determined
from the following equation, assuming that the pressure at the surface datum is
14.7 psia (1 bara):

dP
P w ¼ D ðpsiaÞ or ðbaraÞ
dD
w
3
The water pressure gradient is related to the water density (r w , kg/m ) by the
following equation:

dP
r g ðPa=mÞ
w
dD
w
2
where g is acceleration due to gravity (9.81 m/s ).
Hence it can be seen that from the density of a fluid, the pressure gradient may
be calculated. Furthermore, the densities of water, oil and gas are so significantly
different that they will show quite different gradients on a pressure–depth plot.
This property is useful in helping to define the interface between fluids. The
intercept between the gas and oil gradients indicates the GOC, whilst the intercept
between the oil and water gradients indicates the free water level (FWL) which is
related to the oil–water contact (OWC) via the transition zone, as described in
Section 6.2.9.
The gradients may be calculated from surface fluid densities, or may be directly
measured by downhole pressure measurements using a formation pressure testing
tool (discussed in Section 6.3.6). The interfaces predicted can be used to confirm
wireline measurements of fluid contact, or to predict interfaces when no logs have
directly found the contacts.
For example, in the following situation, two wells have penetrated the same
reservoir sand. The updip well finds the sand gas bearing, with gas down to (GDT)
the base of the sands, whilst the downdip well finds the same sand to be fully oil
bearing, with an oil up to (OUT) at the top of the sand. Pressures taken at intervals in