Page 101 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

Formation Evaluation 89

Table 5-21
Special Core Analysis Tests
Type of test Use of results
Capillary pressure Defines irreducible fluid content, contacts.
Rock compressibility Volume change caused by pressure change.
Permeability and porosity vs. Corrects to reservoir conditions.
pressure
Petrographic studies
mineral Used in log interpretation.
diagenesis Origin of oil and source bed studies.
clay identification Origin of oil and log analysis.
sieve analysis Selection of screens, sand grain size.
Wettability Used in capillary pressure interpretation and
recovery analysis-relative permeability.
Electrical
formation factor Used in log interpretation.
resistivity index
Acoustic velocity Log and seismic interpretation.
Visual inspection Rock description and geological study.
Thin sections, slabs
Air, water, and other liquid Evaluates completion, workover, fracture and
permeability injection fluids; often combined with flood-pot
test.
Flood-pot test and waterflood Results in values for irreducible saturations,
evaluation values for final recovery with special recovery
fluids such as surfactants, water, and polymers.
Relative permeability Relative permeability is used to obtain values
gas-oil for effective permeability to each fluid when two
gas-water or more fluids flow simultaneously; relative
water-oil permeability enables the calculation of recovery
oil-special fluids versus saturation and time while values from
thermal flood-pot test pive only end-point results.
From Reference 180.

Cores that are cleaned with solvents and resaturated with reservoir fluids are
called restored-state cores or extracted cores. The restoring process is often
performed on nonpreserved or weathered cores, but the same technique could
apply to cores that had been preserved.
Two methods of preserving conventional cores, immediately after they have
been removed from the core barrel, will prevent changes in wettability for several
months. One method consists of immersing the core in deoxygenated formation
brine or suitable synthetic brine (i.e., drilling mud filtrate) and keeping the
samples in suitable containers that can be sealed to prevent leakage and the
entrance of oxygen. In the second method, the cores are wrapped in Saran or
polyethylene film and aluminum foil and then coated with wax or strippable
plastic. The second method is preferred for cores that will be used for laboratory
determination of residual oil content, but the first method may be preferred
for laboratory displacement tests. Plastic bags are often recommended for short-
term (24 days) storage of core samples. However, this method will not ensure
unaltered rock wettability. Air-tight metal cans are not recommended because
of the possibility of rust formation and potential leakage.