Page 26 - Primer on Enhanced Oil Recovery

Hydrocarbon and oil reserves classification 17

pressure, temperature, displacement mode, initial phase composition, specific fluid
density, reservoir size, total and effective oil-saturated thickness, sandstone ratio,
lithological composition, formation homogeneity, porosity coefficient, permeability
coefficient and technological scheme of development. Similar strata should also be
close in parameters to the reservoir in question in relation to geological processes
that influenced their formation, including sedimentation, diagenesis, dynamics of
changes in reservoir pressure and temperature, chemical composition and mechani-
cal properties of rocks, as well as tectonic deformations.

2.3.2 Volumetric methods
The essence of the volumetric method is to determine the volume or mass (which
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we obtain by multiplying OOIP (m ) by the average density of oil under standard
conditions) of oil in saturated volumes of reservoir rocks void space.
Volumetric methods are based on the use of geological data. The estimation pro-
cess starts with accounting for the properties of reservoir rocks and their liquids sat-
uration. The model later develops by determination of the recoverable
hydrocarbons, which may be extracted as a result of the development project.
Factors affecting the accuracy of estimating initial geological reserves include:

Geometric shape of the deposit and contours of the trap, affecting the total volume of res-
ervoir rocks.
Geological characteristics that define the volume of the pore space
Reservoir properties related to open porosity and residual water saturation
To calculate the initial geological reserves, as a rule, the average coefficient of
sandiness, porosity and fluid saturation are used. In the process of calculations, it is
also necessary to make assumptions about the natural mode of the reservoir, which
largely determines the nature of the displacement of hydrocarbons in the porous
medium of the reservoirs. The assessment of recoverable reserves (resources)
should reflect the relevant uncertainties not only in relation to the initial geological
reserves, but also the recovery factor RF in accordance with the specific develop-
ment project of the reservoir.
Original Oil In Place is then calculated by:
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OOIP m 5 V φ 1 2 S w Þ=B; (2.3)
ð
where V is trap volume, ɸ is coefficient of open porosity, S w is residual water satu-
ration, B is so named volumetric coefficient which adjust oil volume at the reser-
voir conditions to the oil volume on the surface after volatile part of the
hydrocarbons (essentially gas) and other gases leave the oil.
The rock volume is obtained by multiplying the horizontal projection of the area
of oil deposits (A) by the average value of the vertical effective oil saturated forma-
tion thickness (h). Only pores (voids) in the rock contain reservoir phases and, the,
mobile phases can be only extracted from connected pores. In order to account for