Page 224 - Geology of Carbonate Reservoirs

ROCK PROPERTIES AND DIAGNOSTIC METHODS 205

ogy can be estimated with reasonable accuracy from modern log data, it is not easy
to make accurate petrophysical calculations from multimineral carbonate reservoirs,
as Holtz and Major ( 2004 ) point out in their discussion of Permian dolostone res-

ervoirs in West Texas. They were able to refine their petrophysical calculations by
examining cores to determine the combined mineralogical composition and variety
of pore types that were prevalent in different reservoir zones, again emphasizing
the importance of thorough and accurate rock descriptions. Their work echoes
Focke and Munn ( 1987 ) by emphasizing that pore geometry has a strong infl uence
on petrophysical properties in carbonate reservoirs. Calculations of permeability

and fluid saturation should be made in conjunction with studies of rock samples
because carbonate porosity may not correlate with permeability in the expected
linear relationship, and calculated S w values may be far from correct if the Archie
m value is not chosen according to the dominant pore types.

Distinguishing between flow units, baffles, and barriers is sometimes called “ rock
typing ” and several methods stand out, including those described in Lucia ( 1995 ),
Martin et al. ( 1997 ), and Gunter et al. ( 1997 ). The Lucia rock types are for use on
reservoir rocks with only interparticle porosity. In that case, porosity and permeabil-
ity vary in predictable clusters on semilog plots of particle size and poroperm values.
The Martin et al. ( 1997 ) and Gunter et al. ( 1997 ) rock types are more petrophysical
in character in that they are based on relationships between poroperm values and
pore throat dimensions determined from capillary pressure measurements. Those
methods derive from the “ Winland R 35 ” method. Laboratory measurements such
as mercury injection capillary pressure (MICP) and nuclear magnetic resonance
(NMR) provide important information about capillarity, saturation, fl uid composi-
tion, pore characteristics, pore throat sizes, and size distribution within samples.
MICP data can be used to compute height of the hydrocarbon column in reservoirs
and seal capacity required to prevent hydrocarbon leakage. In addition, median
pore throat diameters calculated from MICP data generally correlate well with
permeability. MICP measurements can be compared with measurements in thin
section of pore geometry and genetic pore category to identify the pore types and
sizes that consistently have the highest correspondence with reservoir performance,

or flow unit quality.
Research on the relationships between NMR and MICP measurements is in its
early stages, at least in academia, but great progress is being made. Current work

indicates that genetic pore types in carbonates can be identified by statistical evalu-
ation of NMR relaxation time curves (Genty et al., 2007 ). Correlations between
NMR, MICP, and pore size – shape are powerful tools for predicting reservoir quality

and behavior at field scale, especially as new generations of NMR logging tools are
developed. Work with laboratory NMR measurements should help develop much
more sophisticated interpretations of carbonate reservoir characteristics. The NMR
logging tool is used for borehole measurements of total NMR porosity, in situ per-

meability, fluid saturations, oil viscosity, and bulk volumes of irreducible water. It is
particularly useful in discriminating pore sizes and pore characteristics in the sub-
surface. The principal limitation of this generation of device is its depth of investiga-
tion. When results of laboratory studies are incorporated in new generation NMR
log interpretations, it may be possible to identify and rank flow units, baffl es, and

barriers by calibrating NMR data with direct measurements from only one or two
cores per fi eld.