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New Applications for Resistivity Tools
With advances in logging technology, the leading oilfield technology
companies have developed an impressive array of tools for a broad range
application. In this section, we will discuss a variety of high resolution
resistivity tools.
Resistivity Imaging Tools
Resistivity imaging tools were introduced during the mid-1980s, as an
outgrowth of dipmeter technology. These tools utilize four to six independent
arms, each with articulating pads containing multiple electrodes. This
combination of multiple pads and numerous electrodes results in vastly-
improved vertical resolution -to the tune of mere fractions of an inch.
A typical tool emits an electrical "survey" current into the formation, while
another current focuses and maintains a high-resolution measurement. The
currents measured by each electrode vary according to formation conductivity,
which reflects changes in fluid properties, permeability, porosity, rock
composition, and grain texture. These variations are processed and converted
into synthetic color or gray-scale images, which are interpreted according to
the following convention:
Light Colors -reflect low micro-conductivity zones, (low porosity, low
permeability and high resistivity)
Dark Colors -reflect high micro-conductivity zones, (high porosity,
high permeability and low resistivity)
Resistivity Imaging Applications
Borehole imagers use a fixed-contrast presentation for gross correlations, and
a dynamic averaging display to enhance local features.
The fixed, or absolute contrast allows the viewer to correlate colorvalues between different zones of interest within the well, or between
images from different wells.
The dynamic averaging display is applied to local events, to allow the
viewer to distinguish features on a smaller scale, such as oil-filled
pores, or tight sands.
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When integrated with a traditional suite of logs, the images produced by a
resistivity imaging tool enable the analyst to differentiate laminated reservoirs
from low-permeability shaly sands. The tool produces quantitative, high-
resolution micro-resistivity measurements that aid in estimating hydrocarbon
saturation and reserves in thin-bedded reservoirs, thus improving the net pay
estimation of laminated reservoirs.
Resistivity Imaging Services
Each of the three leading oilfield technology companies offers their own
unique version of the resistivity imaging tool. And because each company has
its own impressive design, we will feature a photo of each. Examples include:
Halliburton Electrical Micro Imaging (EMITM
)Tool
This tool has six independent arms, with an articulating pad on each arm
(Figure 1: EMITM
tool, courtesy of Halliburton Energy Services).
Figure 1
Each pad contains 25 sensors, with a resolution of 0.2 inches. The central
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Using the high-resolution resistivity measurement results in improved
saturation calculations and more realistic net pay estimations.
Schlumberger Formation MicroImager (FMI TM) Tool
In addition to a 24-button microelectrical array pad on each of four arms (192
buttons total), the FMITM
mounts an extendable pad below each arm, to
increase pad coverage to about 80% of an 8-inch borehole. (Figure 3:FMITM
Tool; courtesy of Schlumberger Oilfield Services) Resolution is 0.2 inch
(5mm),
Figure 3
and the tool is rated to 350r F, and 20,000 psi.
Hybrid Resistivity Imaging Devices
In this section, we discuss two rather unique imaging devices, each of which
features specialized capabilities and operating modes.
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Baker Atlas Simultaneous Acoustic/Resistivity (STARTM
) Tool
Rather than taking only resistivity measurements, this tool simultaneously
acquires high-resolution images of borehole features that have resistivity
contrast or acoustic impedance. This combination of acoustic and resistivity
measurements partially compensates for any shortcomings inherent in eitherof the individual measurements. The six-arms on the tool use a powered
standoff to improve pad contact with the borehole, thus providing resistivity
coverage of 60% of an 8-inch hole, and 100% acoustic coverage. (Figure 4:
STARTM
Tool; courtesy of Baker Atlas.)
Figure 4
The tool is rated to 350r F.
Schlumberger Azimuthal Resistivity Imager (ARITM
) Tool
Instead of relying on pad contact, this tool uses an array of 12 azimuthalelectrodes, spaced 30 degrees apart. (Figure 5:Conceptual drawing of ARI
TM
tool; courtesy of Schlumberger Oilfield Services).
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Figure 5
This dual laterolog array is able to measure deep resistivity, but with a vertical
resolution of only eight inches. This makes for a laterolog reading that is
similar to the laterolog deep curve, but with a vertical resolution thatapproaches that of the MSFL curve. As an imaging tool, the ARI
TMis less
sensitive to borehole rugosity than the FMI electrical imaging tool, and can
also provide coarse structural dip measurements. The tool was developed for
evaluation of heterogeneous reservoirs, thin-bed analysis, and fracture
identification. It is rated to 350rF, and 20,000 psi.
Consult your logging representative for more information on the resistivity
imaging services that their company can provide.
Digital Array Induction Logs -
Digital array induction tools use multiple receivers and multiple logging
frequencies which provide capabilities that are not available with conventional
induction tools.
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this situation, high-resolution data near the borehole are added to
the deeper measurements so that all curves are presented with the
same matched vertical resolution, of 1, 2, or 4 feet.
Schlumberger Array Induction Imager Tool (AITTM
)
This tool uses 8 induction-coil arrays operating at multiple frequencies to
generate five resistivity curves. The log curves have median depths of
investigation of 10, 20, 30, 60, and 90 inches, and vertical resolution options
of 1 foot, 2 feet, and 4 feet. When the logs are radially deconvolved to produce
a detailed radial description of formation conductivity, the conductivity
description can be presented as a color-coded image or as discrete log curves.
Halliburton High Resolution Induction (HRITM
) Tool
tool features five radii of investigation (90, 60, 50, 40, 30, and 24 inches).
Their log also displays a resistivity map to indicate formation resistivity as a
function of depth and radial distance from the HRI tool.
Consult your logging representative for more information on the array
induction services that their company can provide.
3D Multicomponent Resistivity Tool
Conventional induction logging tools use transmitter and receiver coils that
are aligned with the long axis of the tool. In wells drilled perpendicular to
bedding, these tools measure formation conductivity parallel to bedding.
When a reservoir is composed of thinly bedded, highly conductive shales and
hydrocarbon-bearing sands that are below the vertical resolution of the tool,
the result is measurements experience the problematic low-contrast, low-
resistivity pay effect (Mollison, 2001).
Baker Atlas 3D Explorer Induction Logging Service (3DEXTM
)
Baker Atlas has developed a resistivity tool unique to the industry, which isdesigned to overcome the limitations of conventional induction tools in thin
bedded, low-resistivity shaly-sand formations. The Baker Atlas 3D Explorer
Induction Logging Service (3DEXTM
) provides both vertical and horizontal
resistivity measurements independently of borehole deviation or formation
dip.
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The 3DEX features three transmitter-receiver coil arrays, which are mounted
orthogonally in the X, Y, and Z planes relative to the tool axis. These coil
arrays provide 3-D coverage in their resistivity measurements:
two coils (XX and YY) measure resistivity in transverse directions
(parallel to the tool body),
a third coil (ZZ) measures resistivity in the direction of conventional
resistivity tools (perpendicular to the tool body)
in addition, there are cross component measurements (XY and XZ).
These arrays induce currents that flow, for the most part, across laminated
sand-shale sequences, and are far more sensitive to hydrocarbon-bearing sand
resistivity, as shown in Figure 6: Basic principle of operation: Laminated
sand/shale intervals are surveyed by three orthogonal coil arrays.
Figure 6
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Inversion processing of XX-YY-ZZ measurements obtained through the tools
orthogonal coil configuration are used to determine vertical and horizontal
resistivity Rv and Rh. The 3DEX horizontal resistivity is always determined
parallel to the bedding plane, consequently, the vertical resistivity is always
measuredperpendicularto the bedding plane. Thus, regardless of changes in
borehole deviation or apparent strike and dip, the 3DEX measurements of Rv
and Rh remain properly oriented to the formation bedding.
Where there is a difference in values between Rv and Rh, the formation is said
to be electrically anisotropic.
Electrical Anisotropy Effect
Conventional induction logging tools are limited to measurements in one
dimension because their sensors are aligned along the length of the tool (its Z-axis). Such measurements are satisfactory only when formations are at least as
thick as the tools vertical resolution, which is generally several feet.
In the presence of small apparent formation dips, the conventional induction
tools induce currents that mainly flow in the highly conductive beds (typically
shales) of hydrocarbon bearing sections. Thus, when pay zones occur within
thinly bedded sand-shale sequences, the conventional horizontal induction
measurement is dominated by the lowestresistivity, usually found in the shale
layers. As a result of this induced current flow pattern, the horizontal
resistivity (Rh) is relatively insensitive to the higher resistivity of thehydrocarbon-bearing sands. In this manner, relatively small volumes of
conductive shale can significantly reduce the apparent resistivity, thereby
reducing the accuracy of computed hydrocarbon saturations for the sand
layers.
Vertical resistivity, however, is dominated by the highest resistivity
component. In a hydrocarbon reservoir, Rv measurements provide more
information on the resistive sand components, thus yielding more accurate
fluid saturations in the sand layers. The 3DEX tool capitalizes on this
principal, with coil arrays aligned to resolve vertical resistivity.
In a thinly laminated sand-shale sequence, effective horizontal and vertical
resistivities are derived through parallel and series resistor models. The
corresponding formulae are:
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(Equation 1)
where
Rh = horizontal resistivityRsh = shale resistivity,
Rsd = sand resistivity
Vsh = shale volume, and
Vsd = sand volume
such that
Vsh + Vsd= 1
and
(Equation 2)
where
Rv = horizontal resistivity
Rsh = shale resistivity,
Rsd = sand resistivity
Vsh = shale volume, and
Vsd= sand volume
These equations are key to understanding the important differences between
horizontal and vertical resistivity. Equation 1 helps to explain how horizontal
resistivity is affected by shale or by sand:
horizontal resistivity (Rh) is strongly dependent on shale resistivity (usually
low) and shale volume
horizontal resistivity exhibits poor sensitivity to sand resistivity.
Conventional induction tools, with their coils aligned along the length of the
tool, are only able to measure perpendicular to formation bedding, and thusare only sensitive to horizontal resistivity.
Equation 2 demonstrates that vertical resistivity averages the contributions
from both sand and shale, and thereby provides a much better indicator of
thin hydrocarbon-bearing sands.
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The 3DEX tool capitalizes on vertical and horizontal conductivity
measurements to determine the laminar shale volume and laminar sand
conductivity. A Thomas-Stieber-Juhasz evaluation technique is applied to
determine the volume of dispersed shale along with the total and effective
porosities of the laminar sand fraction. By removing laminar shale
conductivity and porosity effects, the laminated shaly sand problem is reduced
to a single dispersed shaly sand model to which the Waxman-Smits equation
can be applied. (For additional details, see the Petrophysical Evaluation
described below.)
Log Example
In this example from Mollison, et al. (2000), the 3DEX tool was used to
evaluate a shaly-sand interval containing three distinct zones, each of which
exhibit different ranges of electrical anisotropy and shale content. Theresulting log is shown in Figure 7.
Figure 7
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The upper sand, from x100 to x145 feet, exhibits a fining-upward
sequence of moderately shaly sand. The data show significant electricalanisotropy (Track 1), as demonstrated by the separation of Rv and Rh (Track
2).
The middle sand, from x145 to x169 feet, is a gas producing zone with
low shale content. This interval exhibits little anisotropy, as would be
expected in a massive, high-porosity sand.
The lower sand, from x169 to x220 feet, is characterized by higher shale
content and higher electrical anisotropy than the upper sand. Conventional,deep-induction resistivity data, HDIL, shown in track 2, would not be able to
effectively identify this interval as a potentially productive sand-shale
sequence. However, the Rv and Rh data improve evaluation accuracy of the
lower sand and properly identify this as a finely laminated sand interval.
Petrophysical Evaluation of the Log
Directional resistivity measurements from the 3D Explorer tool can be used to
compute both the volume of laminar shale and the resistivity of the sand
fraction of a laminated formation without reference to other measurements orshale indicators. The 3DEX petrophysical evaluation model removes the
laminar shale conductivity effects by utilizing electrical anisotropy
measurements Rv and Rh.
In sand-shale sequences, Rv and Rh measurements provide a close link to the
petrophysical model through the direct computation of laminar shale. This
laminar shale volume may be compared to Thomas-Stieber style volumetric
laminar shale calculations, thus yielding a validation of the both petrophysical
models.
Petrophysical analysis of the above log reveals that the shales are
predominantly laminar, with minor amounts of dispersed shale (Track 4). In
the upper sand interval (100 to 145), the calculated laminar-sand resistivity,
Rsd, is 3 to 5 ;-m higher than that indicated by either the deep induction of the
HDIL tool or the horizontal resistivity Rh of the 3D Explorer (Track 2). Water
saturation from the laminar sand analysis is 10% to 15% lower than that
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obtained by standard saturation analysis (Track 3), indicating commercial
hydrocarbon production rates are probable from this interval.
This comparison of laminar shale volumes may also provide valuable
geological information. For example, the presence of anisotropic resistivity
allows important additional interpretation as to the geometry of the layers, i.e., parallel bedding. The lack of resistivity anisotropy would point to a lack of
parallel bedding, such as disturbed, folded or slumped bedding. Such intervals
often tend toward low producibility.
The lower sand interval, from x169 to x220 feet, is the most interesting in this
well. Total shale volume in this interval is 60% to 70%. The separation
between the Rh and Rv curve, together with the resulting anisotropy ratio,
indicate that the formation is almost entirely laminar and thin-bedded, with an
average net-to-gross ratio of 35%. Water saturation through the laminar sandis calculated at 40% to 55%, which agrees well with water saturation values
obtained in the upper sand interval. The net result is a possible 18 feet of
additional pay that might not have been identified by standard resistivity tools
and traditional water saturation analysis methodology.
The 3D Explorer can also provide supplemental measurements for the High
Definition Induction Log (HDIL). It can be run on the same toolstring and and
logged simultaneously, at the same logging speed required by the HDIL tool.
Data processing at the wellsite is provided to expedite the decision-making
process (e.g. testing and completion).
Nuclear Magnetic Resonance Tools
When microporosity, conductive mineralogy, or altered framework grains are
the cause of low-resistivity pay problems, then perhaps an alternative
approach to logging would help the formation evaluation program. In this
case, Nuclear Magnetic Resonance logging, which does not depend on rock
conductivity, can be used to accurately determine hydrocarbon saturation and
distinguish between free water and bound water in the reservoir. (In fact, the
esimation of bulk volume irreducible water, orBVI, is one of the earliest andmost widely used applications of NMR logging.)
The conventional neutron, bulk-density, and acoustic-travel-time porosity-
logging tools are influenced by components of the reservoir rock. Because
reservoir rocks typically have more rock framework than fluid-filled space,
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these conventional tools tend to be much more sensitive to matrix materials
than to pore fluids.
Conventional resistivity-logging tools, while being extremely sensitive to the
fluid-filled space, are traditionally used to estimate the amount of water
present in reservoir rocks, but cannot be regarded as truefluid-loggingdevices. These tools are strongly influenced by the presence of conductive
minerals and, for the responses of these tools to be properly interpreted, a
detailed knowledge of the properties of both the formation and the water in the
pore space is required.
NMR logging tools use a permanent magnet to produce a magnetic field that
excites formation materials. An antenna transmits an oscillating magnetic field
in precisely timed bursts of radio-frequency energy into the formation.
Between these pulses, the antenna is used to listen for the decaying echosignal from hydrogen protons that are in resonance with the field from the
permanent magnet. Since this magnetic resonant frequency depends on the
local strength of the magnetic field, the measurement zone of the tool is a
function of the magnetic field generated, and the radio frequency used.
NMR measurements respond primarily to hydrogen protons in the pore spaces
of the formation, thus providing a measure of water or hydrocarbons in the
rock. Unlike conventional porosity measurements (such as the compensated
neutron tool), this measure of NMR porosity does not include hydrogen bound
in the matrix of the rock, thus providing porosity values that are not influencedby lithology. (Figure 8:MRIL porosity model, Courtesy of Baker Atlas) With
only fluids visible to the NMR tool, it does not need to be calibrated to
formation lithology.
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This response characteristic makes NMR logging tools fundamentally
different from conventional logging tools.
Unique Formation Measurements
NMR tools can provide three types of information, each of which make these
tools unique among logging devices:
information about the quantities of fluids in the rock,
information about the properties of these fluids, and
information about the sizes of the pores that contain these fluids.
Specifically, NMR tools are used determine total porosity, effective porosity,
capillary bound water volume, free water volume, hydrocarbon volume, and
permeability. The basic physics behind NMR interpretation is common to all
such data; however, each of the current NMR logging service companies -
Baker Atlas, Halliburton, and Schlumberger have their own proprietary
interpretation methods. In addition, there are now several companies thatspecialize in the interpretation of NMR data, including NuTech and NMR+.
Schlumberger Combinable Magnetic Resonance Tool (CMRTM
)
The Schlumberger Combinable Magnetic Resonance tool uses a directional
antenna sandwiched between a pair of bar magnets to focus the CMR
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measurement on a 6-in. [15-cm] zone inside the formationthe same rock
volume scanned by other essential logging measurements. As shown in
Figure 9 (CMR tool), it is a compact skid-mounted tool that was designed to
be combinable with many other standard logging tools. The CMR tool is run
in an eccentered configuration.
Figure 9
The vertical resolution of the CMR measurement makes it sensitive to rapid
porosity variations, as often seen in laminated shale and sand sequences. The
sensitive region of the tool is shown in red in Figure 10 (Cross-section of the
CMR tool). This region is approximately 0.5 x 0.5 by 6 long, and is located
about 1.1 inches inside the formation.
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Figure 10
Baker Atlas Magnetic Resonance Imaging Log (MRIL) Service
The Magnetic Resonance Imaging Log run by Baker Atlas provides the
capability to run in combination with other openhole logging instruments
(Figure 11: Schematic of combined tool configuration; Courtesy of Baker
Atlas).
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Figure 11
The tool is run in a centralized configuration to ensure that the sensitive
volume does not include the borehole fluid, and is unaffected by borehole
rugosity. The MRIL measurements can investigate the formation at diameters
of up to 18 inches. This tool can be operated simultaneously at different
frequencies to increase the sensed volume, improve the signal-to-noise ratio,
and allow multiple NMR measurements to be obtained at one time.
HalliburtonMagnetic Resonance Imaging Log (MRIL) Tool
The MRIL-Prime tool was introduced in 1998. Like other MRI tools, this MRI
probe can be tuned to be sensitive to a specific frequency, thereby allowing
the MRI to image narrow slices of the rock formation. Figure 12 (Cylinders of
investigation: Courtesy of Halliburton Energy Services) illustrates the
measurement concept behind the MRIL-Prime tool.
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Figure 12
The diameter and thickness of each thin cylindrical region are selected by
simply specifying the central frequency and bandwidth to which the MRIL
transmitter and receiver are tuned. The diameter of the cylinder is temperature
dependent, but typically ranges from approximately 14 to 16 inches.
Consult your local service company representative for more information on
NMR logging tools.
Log Example
In the first log Figure 13, we see a classic example of a low resistivity zone,
which does not show any potential for future completion.
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Figure 13
This example, provided by Halliburton Energy Services, shows MRI and
resistivity data obtained in a Low Resistivity Pay zone. (Figure 14:MRIL Log
presentation, Courtesy of Halliburton Energy Services)
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Figure 14
Log Description -
Following is a list of curves presented in each track of the log.
Track 1: MRIL porosity derived from T2 bins, along with
Caliper, Gamma Ray, and SP measurements from conventional
logs.
Track 2: MRIL permeability, derived from MRIL
Porosity, Bound Water, and Free Fluid measurements, along with
Deep and Shallow Resistivity from conventional logs.
Track 3: T2 distribution from partially polarized activation
with TE of 0.6 ms (left side of track 3), which is typicallyindicative of clay bound water, and the T2 distribution from fully
polarized activation of a TE of 1.2 ms (right side of track),
usually indicative of capillary bound water and free fluids.
Track 4: The difference between two T2 distributions,
each taken with a TE of 1.2 ms at different polarization times,
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yields hydrocarbon signals within the free fluids. Relative
position indicates hydrocarbon type and viscosity value.
Track 5: Time Domain Analysis of calculated volumes of
oil, gas, and free water in the pore space, which provides a
complete description for the fluids in the invaded zone.
Track 6: MRIL-Resistivity display of MRIAN (MRI
Analysis) model to calculate volume of hydrocarbon and free
water in the pore space, which provides a complete description of
fluids in the uninvaded zone.