Page 103 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

Formation Evaluation 91

where t$ = porosity expressed as a percent
V = pore volume
< = bulk volume
Vgr = grain volume

All volumes should be in consistent units, commonly cm9. If pore volume is
measured directly in cores that contain vugs (such as some carbonates), Equation
5-80 may give erroneously high porosity because the bulk volume may be
erroneously low [188]. If bulk volume of vuggy cores is determined by sub-
merging the core in mercury or water, Equation 5-81 may yield erroneously low
porosity [188]. Thus valid porosity values can only be obtained if bulk volume
and grain volume measurements are accurate.

Permeability. The permeability of core plugs is determined by flowing a fluid
(air gas, or water) through a core sample of known dimensions. If the absolute
permeability is to be determined, the core plug is cleaned so that permeability
is-measured at 100% of the saturating fluid. Methods of measuring permeability
of core plugs are described in API RP-27: Recommended Practice for Deter-
mining Permeability of Porous Media [193]. Equation 5-36 can be used to
calculate permeability of core plugs.

Fluid Saturations. Coring procedures usually alter the fluid content of the
reservoir rock during the coring process. Drilling fluid is jetted against the
formation rock ahead of the coring bit and the core surface as it enters the
core barrel; as a result of this flushing action by the drilling mud filtrate, most
free gas and a portion of the liquid are displaced from the core. When water
base drilling fluid is used, the mud filtrate may displace oil until a condition
of residual oil saturation is obtained. Also, this flushing action may result in
the fluid content of the core being predominately that of the drilling fluid.
When oil base drilling fluid is used, the core sample that is obtained may be
driven to an irreducible water saturation.

Factors Affecting Oil Displaced During Coring. During the coring operation, it
is important to avoid extreme flushing conditions that could cause mobilization
of residual oil [194]. Some of the variables that control the amount of oil flushed
from a core by mud filtrate are: borehole-to-formation differential pressure
(overbalance), coring penetration rate, core diameter, type of drill bit, drilling
mud composition (including particle size distribution), depth of invasion of mud
particles into the core, rate of filtrate production (both spurt loss and total fluid
loss), interfacial tension of mud filtrate, permeability of the formation (both
horizontal and vertical), and nature of the reservoir (uniformity, texture, etc.).
In one type of system investigated in the laboratory [195], the amount of oil
stripped from cores varied directly with the overbalance pressure, filtration
production rate, core diameter and core permeability; it varied inversely with
penetration rate. In that system, the overbalance pressure exerted more inf hence
than the other factors. When large pressure gradients exist near the core bit,
unintentional displacement of residual oil may occur in coring operations. In
this region close to the bit, high velocities caused by this high pressure may
mobilize some of the residual oil. Drilling mud composition can affect sub-
sequent laboratory oil displacement tests in core samples by: changing wettability
of the reservoir rock, altering interfacial tension of the mud filtrate, being
penetrated by mud particles into the zone of interest, and rielding undesirable
f hid loss properties. Since fluids with lower interfacial tension contribute to