Transcript NMR AND ACOUSTIC SIGNATURES IN VUGGY CARBONATE …

Southwest Research Institute
J.O. Parra, C.L. Hackert, Southwest
Research Institute;
H.A. Collier, Collier Consulting;
M. Bennett, South Florida Water
Management District
NMR AND ACOUSTIC
SIGNATURES IN VUGGY
CARBONATE AQUIFERS
Summary
Digital processing of optical macroscopic (OM), scanning electron microscope (SEM), and X-ray
computed tomography (CT) images, as well as petrography, are used to characterize the pore
space of the pore system of vuggy carbonate aquifers in South Florida. The results of this analysis
provide information with which to evaluate nuclear magnetic resonance (NMR) well log signatures
for NMR well log calibration. Saturated and desaturated NMR core measurements aid in estimates
of the irreducible water in the rock and the variable T2 cut-offs for the NMR well log calibration.
The measurements establish empirical equations to extract permeability from NMR well logs.
Analyses of synthetic and observed NMR signatures demonstrate that NMR well logs capture the
micro and macroporosities of the carbonate rock. The CT image processing and the ultrasonic
analysis provide information that helps characterize the acoustic signatures caused by
interconnected and connected vugs in core samples. The ultrasonic core and geotechnical data
provide velocity versus porosity relationships based on flow zone indicators. These relationships
are input into a poroelastic modeling program to determine the squirt-flow lengths associated with
the fluid flow between the matrix and the vugs, and between the vugs. Based on this information,
attenuation and velocity dispersion curves of the vuggy carbonate rock are simulated in the
frequency range of sonic logs and high resolution interwell seismic, which in turn relates velocity
from sonic logs to NMR-derived permeability and porosity. The resulting equations are applied to
predict permeability and porosity images from velocity tomography data recorded between two
wells in a carbonate aquifer in western Hillsboro County, Palm Beach, Florida.
Figure 1.
A 3D view of an X-ray CT
scan image of the
diameter of core 41,
showing an interconnected
vug system typical in
carbonate rock from the
Ocala Limestone
Formation, Palm Beach,
South Florida. This core is
from a limestone with
wackestone texture taken
from a depth of 1138
feet in the Ocala, an
Upper Eocene formation.
The high permeability of
the sample is controlled
by interconnected vugs,
and a stochastic analysis
of the CT image predicts
two length scales: 2.2 and
17 mm in the z-direction,
and 2.4 and 7.2 mm in
the xy-plane.
Figure 2(a).
(a) Calculated density from the X-ray CT data for a slice from core 41. Data
plotted is dry density in g/cc.
Figure 2(b).
(b) A photograph of the end of core 41. This core has extensive cavities that
are captured by the CT images.
Figure 3(a).
(a) 2D density images of cores 7 and 41 show small separated and large interconnected
vugs, respectively. Permeability of core 7, also from the Ocala Formation, is 7 millidarcies;
permeability of core 41 is > 4000 millidarcies.
Figure 3(b).
In (b) and (c), the black line is the
waveform for a homogeneous
saturated core, the green line is
the waveform for a
heterogeneous saturated core,
and the red line is the waveform
for a heterogeneous dry core. (b)
The synthetic waveform for core 7
is almost identical to the
waveform of a uniform,
equivalent core, although reduced
in amplitude. Core 7 has few
cavities and is much more uniform
than core 41.
Figure 3(c).
In (b) and (c), the black line is
the waveform for a
homogeneous saturated core,
the green line is the
waveform for a
heterogeneous saturated
core, and the red line is the
waveform for a
heterogeneous dry core. (c)
The waveforms associated
with core 41 reflect the
heterogeneity of the
carbonate sample.
Figure 4.
Cross plots of 24 measured and calculated P-wave velocities of whole core samples versus permeability. The curves
represent six flow units. The numbers in the plot are squirt-flow lengths in millimeters. Each curve represents a flow zone
indicator (FZI) calculated with the expression FZl = 0.314k/ where  is porosity and k is permeability. The curves
show that P-wave velocity decreases as permeability increases. Also, as permeability increases, squirt-flow length
increases as well, i.e., a large permeability correlates with large flow lengths. The plots suggest that differences between
observed and calculated velocities are due to the presence of vuggy porosity in the cores. We expect that the increase in
permeability with squirt-flow length reflects the presence of connected vugs.
Figure 5.
Attenuation and phase velocity
curves based on whole core samples
associated with the P-wave velocity
versus permeability curve (b) in
Figure 4. Responses are calculated
for squirt-flow lengths of 8 and 15
mm. In general, the curves show
strong dispersion effects caused by
interactions between the rock matrix
and water. Strong attenuations exist
between 1000-15,000 Hz. In the
attenuation curves, the peak
frequency moves toward the low
frequency range as the squirt-flow
increases. This analysis implies that
sonic logs and attenuation
tomography have the potential to
capture fluid flow interactions
between the rock matrix and the
vugs. Specifically, P-wave
attenuation and velocity dispersion
can capture the degree of
connectivity between vugs, or
between the matrix porosity and
vugs.
Figure 5.
Attenuation and phase velocity
curves based on whole core samples
associated with the P-wave velocity
versus permeability curve (b) in
Figure 4. Responses are calculated
for squirt-flow lengths of 8 and 15
mm. In general, the curves show
strong dispersion effects caused by
interactions between the rock matrix
and water. Strong attenuations exist
between 1000-15,000 Hz. In the
attenuation curves, the peak
frequency moves toward the low
frequency range as the squirt-flow
increases. This analysis implies that
sonic logs and attenuation
tomography have the potential to
capture fluid flow interactions
between the rock matrix and the
vugs. Specifically, P-wave
attenuation and velocity dispersion
can capture the degree of
connectivity between vugs, or
between the matrix porosity and
vugs.
Figure 6(a).
(a) Pore size
distribution for core
41 based on multiple
imaging methods.
The two SEM
magnifications and
the OM image have
overlapping scales
of view, so there is a
continuous
distribution of pore
sizes from 0.02 µm
up to 50 µm. From
pore size distribution,
we can predict T2
distribution.
Figure 6(b).
(b) Predicted T2
distribution from the core
in the absence of any bulk
relaxation. In this case,
about half of the porosity
is distributed at T2 decay
times much longer that
those recorded by the
tool.
Figure 6 (c).
(c) By including a bulk
relaxation time (Tb) of .5
seconds, the large pores are
moved within the T2
distribution. As a result a good
fit between the NMR well log
and synthetic signatures are
obtained. This results shows
that Tb is an important
parameter that it should not be
neglected in the analysis of
vuggy carbonates.Matching
the peaks of the pore size
histogram and the well log T2
distribution suggests that
formation relaxivity is near 1.5
µm/s. This is within the range
of acceptable values for
carbonates.
Approximate breakdown of porosity by
imaging method and porosity type
CT (vuggy) = 13%
OM (macro) = 4%
SEM (micro) = 17%
Total porosity from imaging = 33%*
Porosity from core = 32%
Porosity from well log = 39%
*Numbers do not add exactly because of
overlap in SEM and OM length scales.
Figure 7.
Comparison of NMR core signatures
with OM thin sections for cores 4, 6, 21,
32 and 49. The NMR plots contain the
T2 relaxation distributions for both
desaturated and fully saturated samples
overlain on one plot. The NMR
measurements were made for small
plugs having different permeabilities
and porosities than the whole cores.
Figure 7 con’t.
Core # 4 is a limestone
of grainstone texture
with intergranular pores
and vugs. The saturated
T2 distribution exhibits
two pore size peaks at
40 ms and 1000 ms. The
photomicrographs show
localized vugs that are
separated. The T2
distribution reflects the
presence of the separate
vugs (at 1000 ms) and
the intergranular pore
size (40 ms). The plug
permeability is 158 md,
and the whole core
permeability is 1235
md. A heterogeneous
sample.
Figure 7 con’t.
Core # 6 is a
limestone of grainstone
texture with no vugs
and with poorly
interconnected moldic
pores. The T2 exhibits
a peak at 12 ms,
which corresponds to
the matrix porosity of
the grainstone sample.
The permeability of
this plug is close to
zero, and the
permeability of the
whole core is 0.7 md.
A homogenous sample.
Figure 7 con’t.
Core # 21 is a
sandstone with an
average grain size
of 0.095 mm.
Intergranular pores
(igp) with dolomite
cement dominate the
pore system. The T2
distribution peak at
12 ms reflects the
matrix porosity of
the sample. A low
permeability,
homogenous sample
(average
permeability of the
plug is 31 md and
of the whole core is
86 md).
Figure 7 con’t.
Core # 32 is a
limestone of poorlypreserved packstone
texture. Moldic and
intraparticle pores
can be identified.
The T2 distribution
has a peak at about
400 ms, which
corresponds to large
pore size (vuggy
porosity). The
sample is
heterogeneous. The
plug permeability is
220 md, and the
whole core
permeability is 1805
md.
Figure 7 con’t.
Core # 49 is limestone
of packstone texture.
The pore system
comprises common
intraparticle and
intergranular pores,
with moderate amounts
of intercrystalline
pores. The T2 peak is
at 80 ms, which
corresponds to
moderate pore sizes.
The permeability of the
plug is 13 md, and the
permeability of the
whole core is 98 md.
The sample is relatively
homogeneous.
Figure 8.
NMR measurements performed on 18 saturated and desaturated core samples provided the
information to produce T2 relaxation cut-off times (T2c) for use in log calibration. Different
relaxation rates are observed in the data associated with the different rock groups in the
well, which provides the appropriate bound-volume index (BVI) for each core plug. Models
based on flow zone indicator (FZI), NMR derived porosity, and the BVI parameter provide
the relationship to calculate permeability at the core scale.
Figure 9.
Four T2c, selected from cores and the permeability equation given in Figure 8, provide the
calibration parameters to produce NMR-derived permeability in the middle track above. Here the
far right plot shows the T2 distribution in the color scale and overlain red lines. The white log is the
median T2 value, which is used with porosity to discriminate among relaxivity units. The thick red
line is the variable T2 cut-off. For comparison, this figure shows the lithology, porosity and the Vp
and Vs logs.
Figure 10.
Figure 10 con’t.
Permeability data is related to interwell velocity data based on multiple
offset high resolution seismic measurements recorded between the
PBF10 and PBF13 wells at the western Hillsboro site, Palm Beach,
Florida. Crosswell tomography and reflection images were gathered
at the site. We focus on the P-wave velocity image data, illustrated
here with the gamma ray and Vp well logs. The P-wave velocity
extracted from the tomography data set is plotted as a velocity log at
both sides of the interwell velocity image. There is a correlation
between the velocity logs at the two scales (10 kHz and 1 kHz), the
gamma ray logs, and the image data. The difference between the
velocity logs at the two dominant frequencies is due to dispersion.
Based on the poroelastic modeling shown in Figure 5, we expect that
most of the velocity dispersion between the acoustic and seismic data
is due to the permeable rock formation in the region between 1060 to
about 1180 feet. Some of the velocity dispersion is due to scattering
losses associated with lithological changes.
Figure 11.
Figure 11 con’t.
Cross Plots Between Permeability and Porosity with
P-wave Velocity
Since there is a good correlation between P-wave velocity
and permeability at the core scale, as shown in Figure 4,
we correlate the Vp with the NMR-derived permeability
and with the total porosity log. The computed relations are
shown in Figure 11. The figure shows nonlinear
relationships between the Vp and the permeability in the
permeable Ocala carbonates (1070-1200 ft) and in the
Arcadia Formation at depth intervals of 950-1010 ft and
1025-1045 ft. Figure 11 also shows linear relationships
between Vp and the total porosity in both regions.
Figure 12.
Permeability and Porosity Images. The comparison of the permeability log with the
lithology shows a very low permeability in the sandstone, and a moderated permeability
low in the chalky carbonate. The high permeability values correlate with the carbonate with
interparticle porosity, which is consistent with the core data. The permeability and porosity
equations are applied to the velocity pixels to produce the permeability and porosity
images. Here we compare the lithology with the velocity, porosity and permeability images
between 950-1200 ft. A permeable zone between 1100-1200 ft in the interwell region of
wells PBF10 and PBF13 is developed at well PBF10 and decreases toward well PBF13.
Conclusions
Ultrasonic responses based on CT models is a practical technique to
determine the heterogeneous conditions of the rock fabric and the
applicability of acoustics to describe the aquifer formation. The results of
the analysis of the observed and calculated ultrasonic responses leads
to correlations of P-wave velocity and permeability at the core scale.
This suggests that the velocity can be related to permeability at the
borehole and the interwell scales. This concept was supported with
poroelastic modeling by showing the velocity dispersion in the frequency
range between 1 -250 kHz. Furthermore, excellent correlations between
P-wave velocity and porosity and P-wave velocity and permeability at
the borehole scale demonstrate that indeed fluid flow effects can be
related to velocity dispersion. These results have inferred that velocity
images at the interwell scale can be converted to permeability and
porosity distributions between wells PBF 10 and PBF 13. The velocity,
porosity and permeability images correlates with the gamma ray and the
velocity logs. The velocity dispersion between the Vp log and the
tomography log that is observed in the permeable region suggests that
attenuation tomography also can be used to map fluid flow effects in
South Florida aquifers.
Conclusions con’t.
Comparisons of the plug and whole core permeability measurements
suggest the presence of permeability heterogeneity at these two
scales. This heterogeneous condition suggests that NMR whole core
measurements will provide more representative permeability
information than that from plugs. The thin section analysis and core
analysis shown that the NMR well log derived permeability represents
the matrix permeability. Although the NMR well log calibration based
on plugs apparently underestimated the true permeability of the vuggy
formation, the relative permeability correlates with the lithology in the
region between 1000-1200 ft.
This study demonstrates that NMR and acoustic techniques
complement each other to characterize vuggy carbonate formations at
the borehole scale. The final results demonstrate that seismic
techniques can be used to map permeability distributions in the
carbonate aquifer in the Ocala Limestone Formation in Palm Beach,
South Florida.
Acknowledgement
This work was performed with support from the U.S.
Department of Energy (DOE), under contract no. DEAC26-99BC15203. The assistance of Mr. Purna
Halder is gratefully appreciated.