Page 176 - Hydrocarbon Exploration and Production Second Edition

Reservoir Description 163

except that it employs neutrons instead of GRs. The neutrons are slowed down as
they travel through the formation and some are captured. Of the common reservoir
elements, hydrogen has the greatest stopping power. A low count rate at the
detector indicates large number of hydrogen atoms in the formation and, as
hydrogen is present in water and oil in similar amounts, implies high porosity.
Because the neutron tool responds to hydrogen it can be used to differentiate
between gas and liquids (oil or water) in the formation. A specific volume of gas will
contain a lot fewer hydrogen atoms than the same volume of oil or water (at the
same pressure), and therefore in a gas-bearing reservoir the neutron porosity (which
assumes the tool is investigating fluid-filled formation) will register an artificially
low porosity. A large apparent decrease in porosity in the upper section of a
homogenous reservoir interval is often indicative of entering gas-bearing formation.
The sonic tool measures the time taken for a sound wave to pass through the
formation. Sound waves travel in high-density (i.e. low porosity) formation faster
than in low-density (high porosity) formation. The porosity can be determined by
measuring the transit time for the sound wave to travel between a transmitter and
receiver, provided the rock matrix and fluid are known.
The NMR tool magnetically aligns hydrogen protons and then measures the time
taken for this alignment to decay. In a reservoir the hydrogen atoms occur chiefly in
the fluid as either water or hydrocarbon within the pore space. The speed of decay is
proportional to the size of the pore. Hence the NMR tool can not only determine
porosity but also indicate the pore size distribution.

6.4.5. Hydrocarbon saturation
Nearly all reservoirs are water bearing prior to hydrocarbon charge. As hydrocarbons
migrate into a trap they displace the water from the reservoir, but not comple-
tely. Water remains trapped in small pore throats and pore spaces. In 1942,
Archie developed an equation describing the relationship between the electrical
conductivity of reservoir rock and the properties of its pore system and pore fluids
(Figure 6.51).
The relationship was based on a number of observations, firstly, that the
conductivity (C o ) of a water-bearing formation sample is dependent primarily upon
pore water conductivity (C w ) and porosity (f) distribution (as the rock matrix does
not conduct electricity) such that
m
C o ¼ f C w
The pore system is described by the volume fraction of pore space (the fractional
porosity) and the shape of the pore space which is represented by m, known as the
cementation exponent. The cementation exponent describes the complexity of the
pore system, that is how difficult it is for an electric current to find a path through
the reservoir.
Secondly, it can be observed that as water is displaced by (non-conductive) oil in
the pore system, the conductivity (C t ) of an oil-bearing reservoir sample decreases.
As the water saturation (S w ) reduces so does the electrical conductivity of the