Note: Descriptions are shown in the official language in which they were submitted.
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METHODS AND APPARATUS FOR MEASURING FLOW VELOCITY IN A
WELLBORE USING NMR AND APPLICATIONS USING SAME
This is a divisional for Canadian Patent
Application Serial No. 2,401,940 filed September 9, 2002.
FIELD OF THE INVENTION
This invention relates to the field of well
logging of earth wellbores and, more particularly, to
methods for measuring flow velocity in an earth formation
with nuclear magnetic resonance techniques and for using the
measured flow velocity to determine various other important
well logging parameters.
BACKGROUND OF THE INVENTION
Well logging provides various parameters that may
be used to determine the "quality" of a formation from a
given wellbore. These parameters include such factors as:
formation pressure, resistivity, porosity, bound fluid
volume and hydraulic permeability. These parameters, which
are used to evaluate the quality of a given formation, may
provide, for example, the amount of hydrocarbons present
within the formation, as well as an indication as to the
difficulty in extracting those hydrocarbons from the
formation. Hydraulic permeability -- how easily the
hydrocarbons will flow through the
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pores of the formation -- is therefore, an important
factor in determining whether a specific well site is
commercially viable.
There are various known techniques for
determining hydraulic permeability, as well as other
well logging parameters. For example, it is known how
to derive permeability from nuclear magnetic resonance
(NMR) measurements. NMR measurements, in general, are
accomplished by causing the magnetic moments of nuclei
in a formation to precess about an axis. The axis about
which the nuclei precess may be established by applying
a strong, polarizing, static magnetic field (Bo) to the
formation, such as through the use of permanent magnets
(i.e., polarization). This field causes the proton
spins to align in a direction parallel to the applied
field (this step, which is sometimes referred to as
longitudinal magnetization, results in the nuclei being
"polarized"). Polarization does not occur immediately,
but instead grows in accordance with a time constant T1i
as described more fully below, and may take as long as
several seconds to occur (even up to about eight seconds
or longer). After sufficient time, a thermal
equilibrium polarization parallel to Bo has been
established.
Next, a series of radio frequency (RF) pulses
are produced so that an oscillating magnetic field B1 is
applied. The first RF pulse (referred to as the 900
pulse) must be strong enough to rotate the magnetization
from BO substantially into the transverse plane (i.e.,
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transverse magnetization). The rotation angle is given
by:
B,Xp (1)
and is adjusted, by methods known to those skilled in
the art, to be 90 (where tp is the pulse length and y is
the gyromagnetic ratio -- a nuclear constant).
Additional RF pulses (referred to as 1800 pulses where
a= 180 ) are applied to create a series of spin echoes.
The additional RF pulses typically are applied in
accordance with a pulse squence, such as the error-
correcting CPMG (Carr-Purcell-Meiboom-Gill) NMR pulse
sequence, to facilitate rapid and accurate data
collection. The frequency of the RF pulses is chosen to
excite specific nuclear spins in the particular region
of the sample that is being investigated. The rotation
angles of the RF pulses are adjusted to be 90 and 180
in the center of this region.
Two time constants are associated with the
relaxation process of the longitudinal and transverse
magnetization. These time constants characterize the
rate of return to thermal equilibrium of the
magnetization components following the application of
each 90 pulse. The spin-lattice relaxation time (T1) is
the time constant for the longitudinal magnetization
component to return to its thermal equilibrium (after
the application of the static magnetic field). The
spin-spin relaxation time (T2) is the time constant for
the transverse magnetization to return to its thermal
equilibrium value which is zero. Typically, T2
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distributions are measured using a pulse sequence such
as the CMPG pulse sequence described above. In
addition, Bo is typically inhomogeneous and the
transverse magnetization decays with the shorter time
constant T2*, where:
._ +, (2)
T2 z
In the absence of motion and diffusion, the decay with
characteristic time T is due to Bo inhomogeneities
alone. In this case, it is completely reversible and
can be recovered in successive echoes. The amplitudes of
successive echoes decay with T2. Upon obtaining the T2
distributions, other formation characteristics, such as
permeability, may be determined.
A potential problem with the T2 distributions may
occur if the echo decays faster than predicted, for
example, if motion of the measuring probe occurs during
measurements. Under these conditions, the resultant
data may be degraded. Thus, for example, displacement
of the measurement device due to fast logging speed,
rough wellbore conditions or vibrations of the drill
string during logging-while-drilling (LWD) may prevent
accurate measurements from being obtained.
Moreover, it also is known that T2
distributions do not always accurately represent pore
size. For example, G.R. Coates et al., "A New
Characterization of Bulk-Volume Irreducible Using
Magnetic Resonance," SPWLA 38th Annual Logging
Symposium, June 15-18, 1997, describes the measurement
of bound fluid volume by relating each relaxation time
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to a specific fraction of capillary bound water. This
method assumes that each pore size has an inherent
irreducible water saturation (i.e., regardless of pore
size, some water will always be trapped within the
pores). In addition, the presence of hydrocarbons in
water wet rocks changes the correlation between the T2
distribution and pore size.
Hydraulic permeability of the formation is one
of the most important characteristics of a hydrocarbon
reservoir and one of the most difficult quantitative
measurements to obtain. Often permeability is derived
from T2 distributions, created from NMR experiments,
which represent pore size distributions. Finally,
permeability is related to the T2 data. This way to
determine permeability has several drawbacks and is
therefore sometimes inapplicable.
Typically T2 distributions are measured using
the error-correcting CPMG pulse sequence. In order to
provide meaningful results, the length of the recorded
echo train must be at least I. During this time
period, as well as during the preceding prepolarization
period, the measurement is sensitive to displacements of
the measuring device. Further, in some cases, the T2
distributions do not represent pore size distributions,
e.g., hydrocarbons in water wet rocks change the
correlation between T2 distribution and pore size
distribution. Finally, the correlation between pore size
distribution and permeability of the formation is
achieved using several phenomenological formulae that
are based on large measured data sets, displaying
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relatively weak correlation. In carbonates, these
formulae breakdown because of the formations'. complex
pore shapes.
A more direct 'way to measure' permeability is
by measurements of induced flow rates using a packer or
probe tool. Still, this measurement: requires extensive
modeling of the. formation response. which includes the
geometry of the reservoir and of the tool, the mud cake,
and the invasion zone.. - The effort required for modeling
however, could -be- significantly reduced. if flow velocity
could be obtained. It would be advantageous to obtain
flow velocity,. which could be used to determine various
parameters required for modeling so- that the ' number of
variables required. for modeling is reduced.
Some.embodiments of the present invention may
provide apparatus and methods for determining flow
velocity utilizing NMR techniques.-
Some-embodiments of the present invention may
provide methods for determining permeability utilizing NMR
measurements of flow, velocity.
Some ' embodiments ' of the present invention may -
provide .methods for detern3inin9 ' 'the extent -of .drilling '
damage to the formation,. formation pressure, mud.
filtration' rate and changes- in the invaded zone during.
sampling utilizing NMR measurements of flow velocity.
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SUMMARY'=OF THE INVENTION
Some embodiments of the invention may provide
methods and apparatus for determining flow velocity
utilizing nuclear magnetic resonance (NMR), techniques and
for providing measurements of other wellbore parameters
based on the flow velocity measurements. Embodiments-may
include methods and apparatus in which flow velocity is
determined without knowledge. of T2 or the pressure
distribution. The flow velocity measurements are made
using NMR techniques in which the shape of the resonance
region is varied depending on whether radial or vertical
sensitivity is desired. 'In an embodiment that.'requires
knowledge of T3, the decay of the echo.-amplitude is
measured. If both radial and vertical sensitivity are
desired, multiple NMR.devices may be provided in.a
single wellbore tool where each NMR device.is designed
to -measure a specific orientation.
In other embodiments of the present"
invention, NMR determination of:-frequency displacement,
rather than signal=decay,'is. utilized to determine flow
velocity. An advantage of 'these techniques also is that
no reference measurements-need be taken because the
detection of 'signal decay is not employed. This can be
achieved by analyzing the ''echo shape instead of the echo
amplitude or by~standard NMR one-dimensional frequency
selective or two-dimensional methods. In still other
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embodiments, an encoding pulse is substituted
for the traditional 90 pulse, and adiabatic pulses are
substituted for the traditional'180 pulses. These
techniques are advantageous if the Bo. gradient is small,
e.g., in the case of a Bo saddle point, because only an
inhomogeneous field B1 is required, rather than a Bo
gradient.
The methods'and apparatus-of some embodiments of the
present invention for obtaining flow velocity using NMR
techniques also are applicable to-determining various
wellbore parameters during. wellbore drilling operations.
For example, by inducing fluid to flow within the.-
formation such as by withdrawing fluid from the
formation into the NMR-tool or into the wellbore, the
NMR determination of'flow velocity maybe used in
conjunction with a differential pressure. measurement to
provide a direct, small-scale measurement of
permeability due to the fact that the NMR data provides
an extremely localized. measurement of fluid velocity.
Alternatively, the NMR techniques of the present
invention may be used. to obtain an assessment.of-the-
drilling damage to the formation..%
In addition, the NMR techniques of some embodiments of
the present invention may be used to determine-formation pressure by,
establishing conditions in the wellbore (for example, by
using- a packer module) such that no filtration of
wellbore fluid occurs across the mudcake and
simultaneously measuring the pressure at the interface
between the mudcake, and the, formation. Another'
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important parameter that may be determined using the NMR
techniques of the present invention is mud filtration rate
(sometimes referred to as invasion). This parameter may be
particularly important because it provides a direct measure of
the quality of the mud system being employed and may provide an
advance indication of potential problems. Also, the NMR
techniques of the present invention may be used to monitor
changes in the invaded zone during sampling operations. Under
such conditions, it is often important to monitor the migration
of fine mud particles (or "fines") that may give rise to
plugging of the formation where the sampling is being
conducted. Moreover, while the determination of various
operational parameters is described herein, persons skilled in
the art will appreciate that various other parameters may be
obtained utilizing the NMR techniques of embodiments of the
present invention.
According to one aspect of the present invention,
there is provided a method of determining flow velocity of a
fluid in an earth formation utilizing at least one nuclear
magnetic resonance (NMR) tool that is placed in a wellbore in
the formation and which produces a static magnetic field and
measures induced magnetic signals, the method comprising:
inducing the fluid to flow; applying the static magnetic field
from the NMR tool to a volume of the formation, the static
magnetic field polarizing a substantial portion of the
formation that is subject to the static magnetic field;
applying an inhomogeneous oscillating magnetic field to a
specific region of the polarized portion via an encoding pulse
to mark spins in the specific region; reapplying the
inhomogeneous oscillating magnetic field to the specific region
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via an even number of refocusing pulses that induce the
production of measurable signals in the specific region;
measuring amplitude of the induced signals; and deriving the
flow velocity based on the measured amplitude.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic diagram of one embodiment of an
NMR logging apparatus for measuring flow velocity in accordance
with the principles of the present invention;
FIG. 2a is a plan-view schematic representation of
one embodiment of an NMR tool component that may be utilized in
conjunction with the NMR logging apparatus of FIG. 1 in
accordance with the principles of the present invention;
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FIG. 2b is a cross-sectional-view schematic
representation of one embodiment of an NMR tool
component that may be utilized in conjunction with the
NMR logging apparatus of FIG. 1 in accordance with the
principles of the present invention;
FIG. 3a is a plan-view schematic
representation of another embodiment of an NMR tool
component that may be utilized in conjunction with the
NMR logging apparatus of FIG. 1 in accordance with the
principles of the present invention;
FIG. 3b is a cross-sectional-view schematic
representation of another embodiment of an NMR tool
component that may be utilized in conjunction with the
NMR logging apparatus of FIG. 1 in accordance with the
principles of the present invention;
FIG. 4 is a side-view schematic representation
of one embodiment of a pressure measurement tool
component that may be used in conjunction with the NMR
tool components of FIGS. 2 and 3 in accordance with the
principles of the present invention;
FIG. 5 is a schematic diagram of another
embodiment of an NMR logging apparatus in accordance
with the principles of the present invention;
FIGS. 6a-e are schematic examples of acquired
exchange distribution and the effects of frequency
displacement for a given echo in accordance with the
present invention;
FIG. 7 is a flow chart illustrating steps for
determining flow velocity in accordance with the
principles of the present invention; and
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FIG. 8 is a pulse sequence illustrating the
use of adiabatic pulse echoes in accordance with the
present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
The methods and apparatus of the present
invention utilize several techniques to determine
various qualitative parameters regarding a given
formation from NMR measurements. The initial
techniques provide a measurement of formation fluid
speed (i.e., flow velocity) that leads to a
determination of formation pressure and/or mud
filtration rate. To accomplish these techniques, the
NMR tool must include the ability to induce flow in the
formation (one tool component) and to create an NMR
shell in the formation that is used to measure the
induced flow (a second tool component). when the basic
techniques described herein are supplemented by
measurements of local pressure gradient (e.g., by adding
a third tool component to the drill string), the
techniques of the present invention may also provide a
determination of permeability and/or skin damage (i.e.,
the area between the wellbore and the virgin formation).
Described herein are various ways to induce
fluid to flow within the wellbore in conjunction with
the determination of flow velocity. For example, during
drilling, the pressure in the wellbore fluid may be
changed via an external device such as a rig pump.
Alternatively, a tool such as that shown in FIG. 1 and
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described below may be deployed (drilling would not be
occurring under these circumstances) that pumps fluid
into or withdraws it from the packer interval. Still
another way to induce fluid flow is through the use of a
port located on a pad, such as that shown in FIGS. 3a
and 3b and described below, in which case fluid would
again be pumped into or out of the tool.
Various known techniques exist for determining
flow velocity. For example, NMR techniques may utilize
switched gradients to encode flow and diffusion.
However, under certain circumstances switched gradients
may be difficult, if not impossible, to produce, and in
the presence of large static gradients, they may be
negligible. The echo measurements of the present
invention can be produced such that they rely only on
static gradient Bo or B1 fields instead of switched
gradients, and therefore, it works for "inside out" NMR
conditions where measurements are made outside the
magnet configuration.
FIG. 1 shows an illustrative example of an NMR
logging device 100 that measures flow velocity. Logging
device 100 includes four modules including: packer 102,
NMR tool 104, packer 106 and NMR tool 108. While
logging device 100 is shown having four modules, persons
skilled in the art will appreciate that various other
combinations of logging tools may be used, including
other known logging tools that are not mentioned herein.
For example, logging device 100 may be used without NMR
tool 108, in which case device 100 only would have three
modules.
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As shown in FIG. 1, logging device 100 is
located in wellbore 110 that previously has been drilled
in earth formation 112. Logging device 100 is suspended
in wellbore 110 from logging cable 114. It is within
contemplation of this invention for the logging device
100 to be conveyed in the wellbore by drill pipe or
coiled tubing. As described in more detail below, the
principles of the present invention also may be applied
to logging-while-drilling (LWD) operations, in which
case logging device 100 (or the applicable modules
(e.g., packers)) then would be located within a drill
string (not shown) behind the drill bit (not shown).
Also shown in FIG. 1 are flow lines 116, and resonance
lines 118 and 120 that are explained in more detail
below.
It is known that a net displacement of a
resonated substance with respect to its spatial position
in the field maps of the measuring device at the moment
of excitation by a pulse sequence leads to a decreased
decay amplitude (DA) in the measured signal amplitude A.
This displacement may be a product of actual
displacement, translational diffusion or a combination
of both. Normal NMR multi-echo experiments correct to a
high degree for diffusion, so that given sufficiently
short echo spacing only the total displacement due to
diffusion at detection time is important. Directed
flow, however, can be detected even in the presence of
diffusion as long as the displacement due to flow is at
least comparable to the displacement due to diffusion.
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The loss of the I-th echo can be characterized
by a loss factor: Xi = Ai/A i, where A i is the amplitude
of the I-th echo under the same circumstances except for
no displacement. Importantly, the loss factor is
independent of the relaxation time distribution of the
substance being investigated, if the displacement is
caused by a uniform motion with a constant scalar
velocity v, the loss factor vector is a function of v
only (i.e., a single variable). Therefore, velocity v
may be determined from the loss factor vector X'
(vectors herein are denoted with the character ").
This requires that several measurements be made with
varying velocities. Let the measured response vector be
SVA = {A1, .. ., An} and assume a measured response, such
as for v = 0, produces a response vector So" = {A 1, ...,
A0n}, then the characteristic loss factor vector is
directly given by %A = {A1/A 1, .. ., An/A n}. Thus, for a
given measurement apparatus with known field maps and a
fixed pulse sequence, a lookup table of ?'(v) can be
calculated from which v can be derived.
The methods and apparatus of the present
invention utilize an excitation pulse in accordance with
field maps Bo and B1 that cause the resonance region
where spins are excited by the pulse to have a specific
shape. The specific shapes are selected depending on
the general direction of fluid flow that is being
measured. For example, if radial flow is an important
component of a desired measurement, the NMR tool used in
flow velocity measurement is configured such that a
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thin, long, cylindrically-shaped resonance region is
defined. A cylindrically-shaped resonance region is
essentially unaffected by vertical displacements (such
as, for example, vertical movement of logging drill
string 114), while being especially sensitive to radial
movement. It can be created, for example, using an
axisymmetric gradient design for B0 like that employed in
the MRIL tool of the Numar Corporation.
On the other hand, if vertical displacement is
an important factor, the NMR tool may be configured to
provide a resonance region that is essentially a
flattened torus-shape (like a flattened doughnut). A
flattened torus-shaped resonance region, which is
especially sensitive to vertical displacement, may be
created, for example, by using a Jasper-Jackson saddle
point design and tuning the operating frequencies above
the Larmor frequency at the saddle point (see U.S.
4,350,955). When both radial and vertical displacement
are important parameters, two separate NMR tools, such
as tools 104 and 108 of FIG. 1, may be utilized. Under
such circumstances, NMR tool 104 may be configured to
form a cylindrically-shaped resonance region, while NMR
tool 108 may be configured to form a flattened torus-
shaped resonance region. Additionally, if a gradient B1
field is present, it is also possible to utilize a
saddle-point-shaped B0 at resonance.
In addition to determining flow velocity v
from the loss factor a,i, it is also possible to determine
flow velocity by analyzing the echo shape in either the
frequency or time domain. Or, the fact that flow causes
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the phases of the echoes to shift in the x-y plane (of
the conventional NMR "rotating" coordinate system) can
be utilized to characterize the motion and further
enhance resolution. The correction vector 2''(v), thus
can be determined solely by quantitative analysis of the
recorded echo phases and echo shapes in the time domain
or frequency domain and knowledge of the T2 distribution
is not required. In the case of a monotonic gradient G,
it is possible to obtain information about the flow
direction by qualitative analysis of the echo shape.
As described above, FIG. 1 shows one
embodiment of an NMR logging device 100 that includes
two NMR tools 104 and 108, each being configured to
measure a different aspect of flow velocity. As NMR
tool 104 is configured to measure radial displacement,
its resonance region is illustrated by resonance
lines 118, while resonance lines 120 illustrate the
vertically oriented resonance region of NMR tool 108
(note that flow lines 116 pass through resonance
lines 118 and 120). In addition, packers may be used to
create a specific flow path. For example, FIG. 1 shows
NMR tool 104 between packers 102 and 106 in an isolated
portion of wellbore 110. Packers 102 and 106 utilize
expansion components 122 and 124, respectively, to
effectively seal off a portion of the wellbore. Then,
NMR tool 104 induces fluid flow by drawing fluid from
the wellbore into the tool itself through a fluid inlet
port. This creates a local pressure change in the
isolated area which induces a flow of fluid in the
formation (shown in FIG. 1 by flow lines 116).
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FIGS. 2a, 2b, 3a, and 3b show embodiments of
NMR tool components that may be used in accordance with
the principles of the present invention to measure flow
velocity, either in conjunction with the NMR tools of
FIG. 1, or other NMR tool configurations. The NMR tool
components of FIGS. 2a, 2b, 3a, and 3b, as well as the
NMR tool components shown in FIG. 4 also include the
capability to provide pressure measurements when pressed
against the wall of the wellbore (contrary to the device
shown in FIG. 1 that is held away from the wellbore wall
by packer modules). Moreover, while the fields of the
device shown in FIG. 1 are axially symmetric, the fields
of the NMR tool components of FIGS. FIGS. 2a, 2b, 3a,
3b, and 4 are not.
FIGS. 2a and 2b show one embodiment of an
NMR tool pad 200 that could be used on NMR tool 108, NMR
tool 504 (describe below) or in other NMR tool
configurations not shown. Pad 200 includes back-up
plate 202, sealing element 204, and pressure monitor
probes 206. Additionally, resonance region 208, which
is similar to resonance lines 120 of FIG. 1 (but,
contrary to resonance lines 120, are not axially
symmetric), illustrates the sensitivity to motion along
an imaginary line joining the pressure probes 206 (of
FIG. 2a). If used with logging device 100, pad 200
would actually be rotated 90 so that resonance region
208 conforms with resonance lines 120. Moreover, in
order to utilize pressure monitor probes 206, pad 200
must be configured such that it is placed against the
wellbore wall (see, for example, the NMR tool
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configuration shown in FIG. 5 and the corresponding text
below) and hydraulic communication is made between
probes 206 and the formation.
FIGS. 3a and 3b show another embodiment of an
NMR tool pad 300 that could be used on NMR tool 108,
NMR tools 400 and 500 (described below) or on a single
NMR tool (not shown) that is configured to produce two
different resonance regions (i.e., vertical and
horizontal). Pad 300 includes back-up plate 302,
sealing element 304, pressure monitor probes 306
that measure pressure azimuthal gradients 316,
pressure monitor probes 312 that measure elevational
gradients 322 and fluid inlet port 314 that draws
fluid into the logging device. Additionally, resonance
region 308 illustrates the sensitivity to radial motion,
while resonance region 318 illustrates the sensitivity
to vertical motion. It should be noted that, because a
pressure sensor is not placed into the formation, the
radial component of the pressure drop is not measured.
Assuming that the formation is isotropic in the
horizontal plane, then the radial permeability component
is substantially similar to the azimuthal component.
Thus, obtaining an azimuthal measurement via probes 306
provides a radial answer.
It should be noted that, in accordance with
the principles of the present invention, the shaped
resonance regions are not limited simply to cylinders
and flattened-toroids, and that the tools described
above are merely illustrative of how the present
invention may be applied to such devices. For example,
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the pads of FIGS. 2a and 3a are generally sensitive to
motion in the circumferential direction, i.e., rotation
of the drill string within the borehole. Thus, the
present invention may be utilized to produce specific-
shaped resonance regions that are substantially smaller
in one direction than any other direction, and that the
smaller direction is beneficial because it provides
measurements that essentially are unaffected by movement
in that direction. For example, the thin, long,
cylindrically-shaped region is generally unaffected by
vertical movement.
FIG. 4 shows another embodiment of a logging
device 400 that may be used in accordance with the
principles of the present invention. Rather than
utilize a single pad 300 to perform a wide variety of
functions (which accordingly increases the complexity
and expense of producing such a pad), device 400 offers
an alternative when used in conjunction with, for
example, pad 200 of FIG. 2a. Device 400 includes
pressure monitor probes 402, 404 and 406, another NMR
tool (not shown) and a fluid sampling probe 408 that is
used to sample formation fluid instead of fluid inlet
port 314 of pad 300 (see FIG. 3a).
Device 400 has multiple applications. First,
NMR probes 402, 404 and 406 may be utilized to obtain a
small-scale permeability measurement (in both vertical
and horizontal directions) of the invaded zone, i.e.,
the zone of the formation affected by drilling damage.
Second, probes 406 and 408 may be used to perform a
"deeper" permeability measurement by conducting a
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pressure interference test between the probes (provided
the spacing between probes 406 and 408 is sufficiently
large). Probe 408 would be used to create a pressure
pulse by withdrawing fluid into the probe. A comparison
of the two different permeability measurements (i.e.,
the small-scale or invaded zone measurement, and the
"deeper" or virgin reservoir) provides information on
the formation heterogeneity. In addition, if the extent
of the damaged zone is available, for example, from an
array resistivity log, then a value of the "skin" also
may be determined.
Persons skilled in the art will appreciate
that, although three specific configurations of logging
tools have been described, that there are countless
other combinations that may be used to practice the
principles of the present invention. For example, a
fifth probe could be placed opposite probe 402 on
device 400. In such a configuration, probes 404, 406
and 408 may be of the type shown in FIG. 3a, while
probes 402 and the fifth probe may be of the type shown
in FIG. 2a. Device 400 also would have the capability
to determine permeability using the pressure
interference test while determining small-scale
permeability using the NMR techniques described herein.
FIG. 5 shows a schematic illustration of
another embodiment of the present invention in which an
NMR logging device 500 measures local pressure gradients
so that parameters such as permeability and skin damage
may be determined. Logging device 500 includes an NMR
tool 504 and packers 506 and 508. Packers 506 and 508
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operate as described above to create a specific flow
path within the earth formation. NMR tool 504 includes
pressure sensor 530 and NMR tool pads 534 and 536, each
of which may be similar to the NMR tool pads described
above. For example, NMR tool pad 534 may be used to
form resonance region 518 in the formation surrounding
wellbore 510. More importantly, NMR tool 504 also
includes moveable springs 532 that press pressure
sensor 530 against wellbore wall 511 so that local
pressure gradient measurements may be obtained.
To determine the skin damage, probes 534
and 536 determine the small-scale permeability (i.e.,
local permeability of the damaged zone). Fluid then
is flowed into the region between packer modules 506
and 508, which breaks the mudcake seal, to induce a
large pressure pulse. The pressure pulse is used to
perform an interference test between the packer probe
and another probe (not shown) located outside the packer
region. Persons skilled in the art will appreciate that
the small-scale NMR permeability measurement must be
made prior to breaking the mudcake seal and the
interference test when utilizing device 500. Moreover,
with the addition of a pressure gauge (not shown)
located between packer modules 506 and 508, device 500
also may be utilized for the determination of skin and
formation pressure.
When formation pressure is being determined,
packer modules 506 and 508 are utilized to isolate a
portion of the wellbore. NMR probe 504 is utilized to
produce resonance shell 518 that is used to sense when
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there is no mud filtrate invasion into the formation --
that filtrate fluid speed is zero. Pressure monitor
probe 530 senses the pressure on the other side of the
mudcake from the wellbore, while another pressure sensor
(not shown) located between the packers monitors the
pressure in the packer interval. Fluid is then
withdrawn or injected until a zero fluid speed condition
exists, at which point the pressure in the packer
interval should be the same as the formation pressure.
The methods of quantitative interpretation are
simplified when a uniform gradient field is present
because in a uniform gradient G", the relationship
between a displacement vector r"(t) and a change in
resonance frequency Sco also is a function of one
parameter: G" = r" = Sco. Therefore, every change in
resonance frequency corresponds to a particular
displacement and Scot, at the time I*te of echo I can be
related to an average velocity r/(I*te). Every echo I of
a given echo train thus represents an experiment with a
different "mixing" time (I*te) in the sense of the
standard NMR exchange experiments. However, the signal-
to-noise ratio can be enhanced by using all of the
echoes together to extract velocity.
For example, an analysis of the echo shape f(t) (or echo
spectrum f(o))) only provides information regarding where
the sum of the spins moved, but does so in a fast and
efficient manner so that few NMR experiments are needed.
If more information is required, such as a
determination of where each spin is moving, frequency
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selective experiments (either one-dimensional or two-
dimensional) may be performed, but such experiments are
more demanding in terms of measurement time and the
number of measurements required. As a variation from
the previously described NMR techniques, this embodiment
of the present invention requires that the spins be
marked or labeled in dependence of their resonance
frequency by applying RF pulses either immediately
before or after the excitation pulse. The simplest way
of marking would be a saturation sequence that creates a
resonance frequency dependent saturation pattern. A
measurement of velocity may then be obtained by
correlating resonance frequency at two different times.
FIGS. 6a-6e show various schematic examples
of two-dimensional exchange spectra of the I-th echo.
FIG. 6a shows a two-dimensional distribution 602 for
the I-th echo in the absence of displacement and
translational diffusion. FIG. 6b shows a two-
dimensional distribution 604 for the I-th echo that
indicates the influence of strong diffusion (or
statistical displacement). FIG. 6c shows a two-
dimensional distribution 606 that is the result of
displacement occurring in the lower field with a given
velocity v. FIG. 6d shows a similar two-dimensional
distribution 608 that results from motion having the
same velocity, but opposite direction (i.e., into the
high field). Finally, FIG. 6e shows the result of
doubling the velocity shown in FIG. 6d (the result would
be the same whether velocity (v), "mixing" time (I*te) or
echo number (2*1) were doubled). FIGS. 6a-6e show that,
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in this embodiment, only frequency displacement affects
the determination of flow velocity (versus decay
amplitude as described above). Persons skilled in the
art will appreciate that the data shown in FIGS. 6a-6e,
without encoding (i.e., just measuring echo shape)
would appear as curved projections instead of spectra,
as shown by way of illustration in FIG. 6e by dashed
line curves 612 and 614. Similar projections also could
be produced for each of FIGS. 6a-6d, if desired.
FIG. 7 shows a flow diagram that illustrates
the methods of the present invention for determining
flow velocity. In a step 702, the tool is placed in the
wellbore (depending on exactly which tool and the
desired parameters, step 702 may be performed as part of
drilling operations or it may be performed separate from
drilling operations, for example, when local gradient
pressure measurements are necessary). Fluid is induced
to flow in a step 704 in any known manner. For example,
via external pumping using equipment from the top of the
borehole or by utilizing pumping ports on the well
logging tool itself, as shown in FIG. 3a (i.e., fluid
inlet port 314).
A strong, polarizing, static magnetic field is
applied to the formation in a step 706, through the use
of, for example, permanent magnets, that polarizes a
portion of the formation (i.e., longitudinal
magnetization). An oscillating magnetic field then is
applied in a step 708 in accordance with field maps Bo
and B1 to produce a resonance region having a specific
shape dictated by the desired motion sensitivity. The
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oscillating magnetic field is the result of the
application of a series of RF pulses to the formation
which forms a resonance region. The specific shape
of the resonance region, which is determined by the
specific sequence of RF signals, is chosen depending on
the desired axis of sensitivity. For example, a thin,
long, cylindrically-shaped resonance region may be
produced for measurements that require minimal impact by
vertical displacement of the drill string.
The sequence of applied RF pulses excites
specific nuclear spins in the formation that induce a
series of spin echoes. The spin echoes induced by the
oscillating magnetic field are measured in a step 710.
The decay loss factor is determined in a step 712 (e.g.,
if there is no movement, the decay loss factor will be
unity). Finally, the flow velocity is derived, in a
step 714, from the decay loss factor. Persons skilled
in the art will appreciate that other parameters, such
as permeability, require additional steps not shown in
FIG. 7 (for example, in order to determine permeability,
a step of measuring local pressure gradients must be
added).
One advantage of the change in resonance
frequency measurement of flow velocity is that, for
identical conditions, the resonance frequency
measurement provides detection of much smaller
displacement velocities compared to the decay amplitude
embodiment previously described. However, the frequency
selective analyses (both one-dimensional and two-
dimensional) require the presence of a uniform gradient
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field that is not a requirement of the echo shape and
decay analysis. Thus, under circumstances where a
uniform gradient exists and very thick resonance regions
are required, resonance frequency measurements may be
particularly advantageous. Moreover, the spread in
displacement could be analyzed in terms of free fluid,
bound fluid, viscosity or the interaction of the fluid
with the rock surface to provide additional information
about the formation and the fluids present therein.
Many of the previously described NMR
measurements of flow velocity rely on a relatively high
gradient in Bo. Therefore, those measurement techniques
are not useful under circumstances where saddle-point
measurements need to be made. A saddle-point tool can
be used to measure flow velocity, however, a gradient in
the pulse amplitude B1 is present. There are various
known techniques for applying magnetic field gradients
to produce stimulated echoes, however, those techniques
all require an inhomogeneous B1 encoding pulse followed
by the application of a homogeneous B1 refocusing pulse
and homogeneous B1 reading pulses. Inside out NMR
saddle-point tools naturally produce the required
strongly inhomogeneous B1 field (from the RF coil), but
the substantially homogeneous B1 field simply is not
achievable.
The refocusing/reading pulse may, in
accordance with the present invention, be accomplished
with the inhomogeneous B1 field by utilizing adiabatic
methods as shown in FIG. 8. For example, following
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encoding pulse 802 (that spirals the spins between the
longitudinal and a transverse direction), a series of
adiabatic refocusing pulses (AFP) 804 are applied to
create an echo train. The echo train is then spooled
back by applying a negative encoding pulse 806 to decode
the echo train. Then, excitation may be performed
adiabatically by applying an adiabatic fast half passage
pulse (AHP) 808 into the resonance zone just prior to
the application of detection sequence 810.
Detection sequence 810 may be accomplished
by applying an adiabatic fast half passage pulse into
the resonance zone -- starting at a frequency outside of
the resonance zone, varying the frequency of the
refocusing pulse so that it sweeps through the entire
resonance zone, and stopping at the resonance frequency.
Alternately, the B0 field may be varied instead of the
frequency. In addition, if diffusion is present, its
effects may be suppressed by applying a multi-echo
sequence with many refocusing pulses, such as refocusing
pulse sequence 804, to introduce phase errors that
cancel themselves out when an even number of refocusing
pulses are applied. For the detection sequence, a
single echo or a multi-echo train may be utilized.
Effective excitation may be provided by an adiabatic
pulse by applying an adiabatic half passage pulse to
turn the spins into the transverse plane.
The capability to measure flow velocity
provides additional advantages. For example, NMR
apparatus may be installed within a drill string and
operated during a pause in drilling operations to
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provide immediate feedback. One particularly useful
parameter that may be determined is a direct measurement
of permeability based on Darcy's formula which states:
v= 1 K*grad*p (3)
ll
where v represents seepage velocity, represents fluid
viscosity, K represents the permeability (tensor) and p
is the local value of the fluid pressure. In earth
formations at the scale of the measurements addressed
herein, the permeability K is essentially determined by
two independent values Kh and Kv (i.e., the horizontal
component and the vertical component, respectively).
By applying the NMR measurements described
above to determine local fluid velocity, values for Kh
and Kv may be directly obtained (provided that probes
are set to measure local pressure gradients, such as the
configurations shown in FIGS. 4 and 5). For example,
Kv = iv,/ dp/dz. Assuming the fluid viscosity g is
known, dp/dz easily may be obtained through the use of
pressure monitor probes, and because vz is determined
based on one of the above-described NMR measurements, Kõ
can be determined. If it is assumed that the
permeability is isotropic in the transverse plane, then
an azimuthal measurement of the pressure gradient
utilizing pressure monitor probes and a measurement of
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fluid velocity (as described above) provides Kh (based on
the derivation that Kh = gvor,,,/ dp/dO) . Once Kh and KV
are determined, permeability K is also determined, in
this case in situ. However, it should be noted that, as
described above, because local pressure gradient
measurements can not be obtained during drilling
operations (because the sensor probes must be placed
against the wellbore wall), neither can permeability
measurements be made during drilling operations.
Another parameter that may be determined using
the flow velocity measurements of the present invention
is an assessment of drilling damage (i.e., the
alteration of permeability into the formation a radial
distance rd due to drilling operations) . This assessment
may be determined by determining the additional pressure
drop or "skin" S associated with the altered region of
the formation when fluid flows into the wellbore (as
this assessment also relies on a measurement of local
pressure gradient, it also cannot be performed during
drilling operations). The determination of S is based,
at least in part on the permeabilities of the virgin
formation and the damaged formation. Thus, skin S may
be calculated as follows:
S= K -I In rd (4)
Ka rtiõ
where r,,, is the wellbore radius, and K. and Kd are the
permeabilities of the virgin formation and damaged
zones, respectively. Accordingly, once rd is determined
from for example, array resistivity logs, a detailed,
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depth-resolved model of the damaged zone can be
constructed and a value of the skin may be determined.
It is also possible to take measurements of
formation pressure, however, such measurements, as
explained above, also cannot be taken while drilling is
active. Formation pressure may be measured by applying
the velocity measurement principles described above, and
detecting the condition when the formation fluid is at
rest (i.e., motionless). This may be accomplished by
manipulating the wellbore pressure while monitoring the
measured velocity. When the measured velocity is zero,
the local pressure at the test depth must be equal to
that of the formation (such that no fluid flows either
from the wellbore into the formation (i.e., invasion),
or vice versa). At that instant, the mud pressure,
which can be determined using conventional tools, is an
accurate measure of the formation pressure.
It should be recognized that it may be
difficult to determine the zero velocity condition,
because resolution decreases at low velocities. In that
case, formation velocity could be measured while
adjusting wellbore pressure in discrete steps. A
plot of the measured velocity as a function of local
wellbore pressure may be extrapolated to determine the
pressure at which zero velocity would occur. While
nonlinearities in the mudcake transmissivity may be
manifested in the pressure-velocity relationship, such
steps may be necessary where it is prohibitive to reduce
the well pressure well below formation pressure.
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When, for reasons of well control, safety or
precision in measurement, it is desirable to adjust the
pressure in the entire weilbore, the local formation
pressure may be determined by the application of
principles shown in FIG. 5, as described above. An NMR
experiment to measure formation pressure could be
conducted using a three module logging device where a
radially sensitive NMR tool is located between two
packer modules (as shown by modules 504, 506 and 508).
The packer modules 506 and 508 could isolate a portion
of the wellbore 510 and NMR module 504 could include a
pumpout unit that would inject and/or extract fluid
into/from the isolated interval in order to adjust the
pressure in the isolated portion of the wellbore. A
conventional pressure probe 530 also could be utilized
within the packer interval that directly measures the
pressure of the sandface interface (i.e., the interface
between the mudcake and the formation) in order to
accurately determine the transmissivity of the mudcake.
Such techniques may not be suitable for low
permeability formations where steady pressure conditions
may not be achievable in the time period allocated for
testing.
The development of the mudcake itself is
another important parameter that may be determined in
accordance with the NMR measurements of velocity
described above. It is important to be able to
determine the rate of loss of mud filtrate into the
formation (i.e., invasion), which is an accurate
indicator of the overall quality of the mud system being
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employed. Mud filtration rate may be determined by
integrating fluid flow measurements over a cylindrical
surface concentric with the wellbore. The result is a
direct measurement of the volumetric flux of the
invading fluid provided that near steady-state
conditions are present (for example, the rate at which
mud filtrate invades the formation should be
substantially constant). Thus, this parameter also
cannot be determined while drilling is occurring.
