U.S. patent application number 10/241965 was filed with the patent office on 2003-03-20 for methods and apparatus for measuring flow velocity in a wellbore using nmr and applications using same.
Invention is credited to Poitzsch, Martin, Pop, Julian, Speier, Peter.
Application Number | 20030052672 10/241965 |
Document ID | / |
Family ID | 25492321 |
Filed Date | 2003-03-20 |
United States Patent
Application |
20030052672 |
Kind Code |
A1 |
Speier, Peter ; et
al. |
March 20, 2003 |
METHODS AND APPARATUS FOR MEASURING FLOW VELOCITY IN A WELLBORE
USING NMR AND APPLICATIONS USING SAME
Abstract
The present invention provides methods and apparatus for
determining flow velocity within a formation utilizing nuclear
magnetic resonance (NMR) techniques in which the shape of the
resonance region is restricted so that sensitivity to radial flow
or vertical flow is obtained (or both when more than one NMR tool
is used). Flow velocity using these NMR tools is determined using
decay amplitude, frequency displacement or stimulated echoes (where
the spins are stored along the magnetic field instead of the
transverse plane to exploit echo decays and frequency
displacements) based on the application of adiabatic pulses. Based
on the described NMR measurement of flow velocity, additional
wellbore parameters may be obtained such as a direct measurement of
permeability, an assessment of drilling damage to the wellbore,
formation pressure, invasion rate of the mud filtrate or the
migration of fine mud particles during sampling operations.
Inventors: |
Speier, Peter; (Stafford,
TX) ; Pop, Julian; (Houston, TX) ; Poitzsch,
Martin; (Sugar Land, TX) |
Correspondence
Address: |
Office of Patent Counsel
Schlumberger Oilfield Services
P.O. Box 2175
Houston
TX
77252-2175
US
|
Family ID: |
25492321 |
Appl. No.: |
10/241965 |
Filed: |
September 12, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
10241965 |
Sep 12, 2002 |
|
|
|
09951914 |
Sep 10, 2001 |
|
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Current U.S.
Class: |
324/303 ;
324/300; 324/306 |
Current CPC
Class: |
G01R 33/563 20130101;
G01N 24/081 20130101; G01V 3/32 20130101 |
Class at
Publication: |
324/303 ;
324/300; 324/306 |
International
Class: |
G01V 003/00 |
Claims
We claim:
1. 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 oscillating magnetic field to a specific part of
the polarized portion to induce the production of measurable
signals, the oscillating magnetic field being applied in accordance
with field maps B.sub.O and B.sub.1 so that a resonance region
having a specific shape corresponding to a desired sensitivity is
formed in the formation; measuring the induced signals; determining
a decay loss factor from the measured induced signals; and deriving
the flow velocity based on the determined decay loss factor.
2. The method of claim 1, wherein the desired sensitivity
corresponds to radial flow and the shape is a thin, long
cylindrical shell.
3. The method of claim 1, wherein the desired sensitivity
corresponds to vertical flow and the resonance region is flattened
torus-shaped region.
4. The method of claim 1, wherein the resonance region having a
specific shape is sensitive to circumferential motion.
5. The method of claim 1, wherein the measurement of the induced
signals comprises: measuring amplitude of the induced signals.
6. The method of claim 1, wherein the induced signals are produced
from spin echoes, each having an echo shape and phase, and the
decay loss factor is determined by quantitatively analyzing the
echo shapes and echo phases in time domain.
7. The method of claim 1, wherein the induced signals are produced
from spin echoes, each having an echo shape and phase, and the
decay loss factor is determined by quantitatively analyzing the
echo shapes and echo phases in frequency domain.
8. The method of claim 1, wherein the induced signals are produced
from spin echoes, each having an echo shape and phase, the method
further comprising: determining flow direction by quantitatively
analyzing the echo shapes in frequency domain.
9. The method of claim 1, wherein the induced signals are produced
from spin echoes, each having an echo shape and phase, the method
further comprising: determining flow direction by quantitatively
analyzing the echo shapes in time domain.
10. The method of claim 1, wherein the resonance region is
saddle-point-shaped.
11. The method of claim 1, wherein the desired sensitivity includes
radial flow and vertical flow, and applying the oscillating
magnetic field comprises: applying via a first NMR tool a first
oscillating magnetic field, the first oscillating magnetic field
being applied in accordance with specific field maps B.sub.O and
B.sub.1 so that a resonance region having a thin, long cylindrical
shell shape is formed in a first specific part of the polarized
portion to induce the production of measurable signals that are
sensitive to radial flow; and applying via a second NMR tool a
second oscillating magnetic field, the second oscillating magnetic
field being applied in accordance with specific field maps B.sub.O
and B.sub.1 so that a resonance region having a flattened torus
shape is formed in a second specific part of the polarized portion
to induce the production of measurable signals that are sensitive
to vertical flow.
12. The method of claim 11, wherein the first and second NMR tools
are included within a drill string and NMR measurements of flow
velocity are made while drilling of the wellbore occurs.
13. The method of claim 11, further comprising: taking a local
pressure gradient measurement; deriving a horizontal component of
flow velocity from the measurable signals induced by the first NMR
tool; deriving a vertical component of flow velocity from the
measurable signals induced by the second NMR tool; and deriving a
measurement of permeability from the horizontal component, the
vertical component and the local pressure gradient measurement.
14. The method of claim 1, wherein the NMR tool is included within
a drill string and NMR measurements of flow velocity are made while
drilling of the wellbore occurs.
15. The method of claim 1, further comprising distinguishing
diffusion from induced fluid flow.
16. The method of claim 1, wherein applying an oscillating magnetic
field comprises: applying a sequence of refocusing pulses that
induce spin echoes to be produced, the spin echoes corresponding to
the measurable signals.
17. The method of claim 16, wherein the sequence of refocusing
pulses is applied in accordance with a CPMG pulse sequence.
18. 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 having a uniform gradient and
measures induced magnetic signals, the method comprising: inducing
the fluid to flow; applying the static magnetic field having a
uniform gradient 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
oscillating magnetic field to a specific part of the polarized
portion of the formation to induce the production of measurable
signals, the oscillating magnetic field being applied in accordance
with field maps B.sub.O and B.sub.1 so that a resonance region
having a shape that corresponds to a desired sensitivity is formed
in the formation; measuring resonance frequency of the induced
signals; and correlating changes in resonance frequency at
different times to a displacement to determine flow velocity.
19. The method of claim 18, wherein the desired sensitivity
corresponds to radial flow and the shape is a thin, long
cylindrical shell.
20. The method of claim 18, wherein the desired sensitivity
corresponds to vertical flow and the resonance region is a
flattened torus-shaped region.
21. The method of claim 18, wherein the resonance region having a
shape is sensitive to circumferential motion.
22. The method of claim 18, wherein the induced signals are
produced from spin echoes and the correlation of changes in
resonance frequency comprises: gathering an exchange distribution
for a given spin echo; and evaluating the exchange distribution to
determine whether displacement has occurred.
23. The method of claim 22, further comprising: evaluating the
exchange distribution, if displacement has occurred, to determine a
direction of the displacement.
24. The method of claim 23, further comprising: evaluating the
exchange distribution, if displacement has occurred, to determine
relative magnitude of the displacement.
25. The method of claim 22, further comprising: calculating a
relaxation time T.sub.2 for each frequency component of the
exchange distribution; and establishing a relationship between
relaxation time T.sub.2 and flow velocity for each frequency in the
exchange distribution.
26. The method of claim 18, wherein the desired sensitivity
includes radial flow and vertical flow, and applying the
oscillating magnetic field comprises: applying via a first NMR tool
a first oscillating magnetic field, the first oscillating magnetic
field being applied in accordance with specific field maps B.sub.O
and B.sub.1 so that a resonance region having a having a thin, long
cylindrical shell shape is formed in the formation to induce the
production of measurable signals that are sensitive to radial flow;
and applying via a second NMR tool a second oscillating magnetic
field, the second oscillating magnetic field being applied in
accordance with specific field maps B.sub.O and B.sub.1 so that a
resonance region having a having a flattened torus shape is formed
in the formation to induce the production of measurable signals
that are sensitive to vertical flow.
27. The method of claim 26, wherein the first and second NMR tools
are included within a drill string and NMR measurements of flow
velocity are made while drilling of the wellbore occurs.
28. The method of claim 26, further comprising: taking a local
pressure gradient measurement; deriving a horizontal component of
flow velocity from the measurable signals induced by the first NMR
tool; deriving a vertical component of flow velocity from the
measurable signals induced by the second NMR tool; and deriving a
measurement of permeability from the horizontal component, the
vertical component and the local pressure gradient measurement.
29. The method of claim 18, wherein the NMR tool is included within
a drill string and NMR measurements of flow velocity are made while
drilling of the wellbore occurs.
30. The method of claim 18, further comprising distinguishing
diffusion from induced fluid flow.
31. The method of claim 18, wherein applying an oscillating
magnetic field comprises: applying a sequence of refocusing pulses
that induce spin echoes to be produced, the spin echoes
corresponding to the measurable signals.
32. The method of claim 31, wherein the sequence of refocusing
pulses is applied in accordance with a CPMG pulse sequence.
33. The method of claim 32 further comprising: performing an
echoeshape analysis on the measured signals.
34. The method of claim 18, wherein applying an oscillating field
comprises: applying a sequence of RF pulses to mark spin
echoes.
35. The method of claim 34, wherein correlating changes in
resonance frequency comprises: performing frequency selective
experiments on the measured induced signals by correlating
resonance frequency of the induced signals at different times.
36. 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 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.
37. The method of claim 36, wherein the inhomogeneous oscillating
magnetic field is applied in accordance with field maps B.sub.O and
B.sub.1 to produce a long cylindrically shell-shaped resonance
region in the formation and the determination of flow velocity is
sensitive to radial flow.
38. The method of claim 36, wherein the inhomogeneous oscillating
magnetic field is applied in accordance with field maps B.sub.O and
B.sub.1 to produce a flattened torus-shaped resonance region in the
formation and the determination of flow velocity is sensitive to
vertical flow.
39. The method of claim 36, wherein the inhomogeneous oscillating
magnetic field is applied in accordance with field maps B.sub.O and
B.sub.1 to produce a shaped resonance region in the formation and
the determination of flow velocity is sensitive to circumferential
flow.
40. The method of claim 36, wherein the inhomogeneous oscillating
magnetic field is applied in accordance with field maps B.sub.O and
B.sub.1 to produce a saddle-point-shaped resonance region in the
formation.
41. The method of claim 36, wherein applying the inhomogeneous
oscillating magnetic field comprises: applying, via a first NMR
tool, a first encoding pulse in accordance with specific field maps
B.sub.O and B.sub.1 to produce a resonance region having a long
cylindrical shell-shape to establish rotation in spins located in a
first part of the specific region and to induce the production of
measurable signals that are sensitive to radial flow; and applying,
via a second NMR tool, a second encoding pulse in accordance with
specific field maps B.sub.O and B.sub.1 to produce a resonance
region having a flattened torus-shape to establish rotation in
spins located in a second part of the specific region and to induce
the production of measurable signals that are sensitive to vertical
flow.
42. The method of claim 41, wherein reapplying the inhomogeneous
oscillating magnetic field comprises: reapplying, via a first NMR
tool, at least a first even number of refocusing pulses having the
same inhomogeneous oscillating magnetic field as the first
adiabatic encoding pulse to the first part of the specific region;
and reapplying, via a second NMR tool, at least a second even
number of refocusing pulses having the same inhomogeneous
oscillating magnetic field as the second adiabatic encoding pulse
to the second part of the specific region.
43. The method of claim 42, wherein the first and second NMR tools
are included within a drill string and NMR measurements of flow
velocity are made while drilling of the wellbore occurs.
44. The method of claim 42, further comprising: taking a local
pressure gradient measurement; deriving a horizontal component of
flow velocity from the measurable signals induced by the first NMR
tool; deriving a vertical component of flow velocity from the
measurable signals induced by the second NMR tool; and deriving a
measurement of permeability from the horizontal component, the
vertical component and the local pressure gradient measurement.
45. The method of claim 36, wherein the NMR tool is included within
a drill string and NMR measurements of flow velocity are made while
drilling of the wellbore occurs.
46. The method of claim 36, wherein the induced signals are echoes
and measuring amplitude of the induced signals comprises: detecting
a single echo.
47. The method of claim 36, wherein the induced signals are echoes
and measuring amplitude of the induced signals comprises: detecting
a multi-echo train.
48. The method of claim 36, wherein the specific region has a
resonance region and reapplying the inhomogeneous oscillating
magnetic field comprises: applying an adiabatic fast full passage
pulse through the resonance region by varying the frequency of the
refocusing pulses so that the pulses are applied prior to one end
of the region, through the region, and up to resonance
frequency.
49. The method of claim 36, wherein the specific region has a
resonance region and applying the inhomogeneous oscillating
magnetic field comprises: applying an adiabatic fast half passage
pulse into the resonance region by varying the frequency of the
adiabatic pulses so that the pulses are applied prior to one end of
the region and into the region.
50. The method of claim 36, wherein the even number of refocusing
pulses comprise a plurality of refocusing pulses that suppress
decay due to translational diffusion so that amplitude measurements
are dependent mainly on velocity only when diffusion is
present.
51. The method of claim 36, further comprising distinguishing
diffusion from induced fluid flow.
52. A method of measuring permeability of an earth formation, the
measurement utilizing a plurality of nuclear magnetic resonance
(NMR) tools that are included within a drill string, the method
comprising: inducing fluid to flow; applying a first static
magnetic field from a first NMR tool to a first volume of the
formation, the first static magnetic field polarizing a first
substantial portion of the formation that is subject to the first
static magnetic field; applying a first oscillating magnetic field
to a specific part of the first polarized portion to induce the
production of measurable signals, the first oscillating magnetic
field being applied in accordance with specific field maps B.sub.O
and B.sub.1 to produce a first resonance region having a thin, long
cylindrical shell-shape in the first volume, the first resonance
region having a sensitivity to radial flow; applying a second
static magnetic field from a second NMR tool to a second volume of
the formation, the second static magnetic field polarizing a second
substantial portion of the formation that is subject to the second
static magnetic field; applying a second oscillating magnetic field
to a specific part of the second polarized portion to induce the
production of measurable signals, the second oscillating magnetic
field being applied in accordance with specific field maps B.sub.O
and B.sub.1 to produce a second resonance region having a flattened
torus shape in the second volume, the second resonance region
having a sensitivity to vertical flow; measuring the induced
signals; taking a local pressure gradient measurement; deriving a
horizontal component of flow velocity from the measurable signals
induced by the first NMR tool; deriving a vertical component of
flow velocity from the measurable signals induced by the second NMR
tool; and deriving a measurement of permeability from the
horizontal component, the vertical component and the local pressure
gradient measurement.
53. The method of claim 52, wherein the formation includes a virgin
zone that has not been affected by drilling of the wellbore and a
damaged zone that has been affected by drilling of the wellbore,
the shell-shaped resonance region and the flattened torus-shaped
resonance regions being located at a radial distance from an axis
of the wellbore, the wellbore having a skin that corresponds to
pressure drop associated with the damaged zone, the method further
comprising: measuring a radial extent of the damaged zone;
measuring permeability of the virgin zone; adjusting the radial
distance of the first and second resonance regions to provide a
depth resolved plurality of velocity measurements; determining a
permeability measurement for at least some of the velocity
measurements; deriving a permeability measurement for the damaged
zone from the determined permeability measurements; and determining
the skin based on the radial extent of the damaged zone, the
permeability of the virgin zone and the permeability of the damaged
zone.
54. A method of measuring formation pressure of an earth formation
utilizing at least one nuclear magnetic resonance (NMR) tool placed
in a wellbore in the formation, the wellbore being at a wellbore
pressure and having an annular mudcake at a pressure between the
NMR tool and the formation, the method comprising: measuring the
pressure of the wellbore as a function of time; inducing fluid to
flow; applying a 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 oscillating magnetic field to a
specific part of the polarized portion to induce the production of
measurable signals, the oscillating magnetic field being applied in
accordance with field maps B.sub.O and B.sub.1 to produce a
resonance region having a thin, long cylindrical shell-shape that
is sensitive to radial flow; measuring the induced signals;
deriving a horizontal component of flow velocity from the measured
signals; monitoring the derived flow velocity while varying
wellbore pressure until a zero velocity condition is obtained; and
providing the wellbore pressure when zero velocity occurred as the
measure of formation pressure.
55. The method of claim 54, wherein formation pressure for a
particular zone of the formation is determined by creating a
specific flow path in the particular zone between a pair of first
and second packer modules, the NMR tool being located between the
first and second packer modules.
56. The method of claim 55, further comprising: utilizing a
pressure measurement probe between the first and second packer
modules to provide a pressure measurement at an interface between
the mudcake and the formation; determining transmissivity of the
mudcake based on the pressure measurement probe measurement, the
wellbore pressure measurement and the horizontal component of flow
velocity.
57. A method of measuring mud filtration rate of a wellbore in an
earth formation, the wellbore having a mudcake region, utilizing at
least one nuclear magnetic resonance (NMR) tool placed in the
wellbore in a substantially steady-state condition, the method
comprising: introducing mud into the wellbore at a substantially
constant pressure; allowing the mud to diffuse through the mudcake
region and into the formation under the influence of the
substantially constant pressure; applying a 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 oscillating
magnetic field to a specific part of the polarized portion to
induce the production of measurable signals, the oscillating
magnetic field being applied in accordance with field maps B.sub.O
and B.sub.1 to produce a resonance region having a thin, long
cylindrical shell-shape that is sensitive to radial flow; measuring
the induced signals; deriving a horizontal component of flow
velocity from the measurable signals induced by the NMR tool; and
integrating the derived flow velocity over a cylindrical surface
concentric with the wellbore to provide a volumetric flux of the
mud filtrate invading the formation.
58. Apparatus for measuring flow velocity in a wellbore in an earth
formation utilizing nuclear magnetic resonance (NMR) techniques,
the apparatus comprising: a first NMR tool that provides a first
static magnetic field to polarize a first substantial portion of
the formation that is subject to the first static magnetic field,
and provides a first oscillating magnetic field to a specific part
of the polarized portion to induce the production of measurable
signals, the first oscillating magnetic field being provided in
accordance with specific field maps B.sub.O and B.sub.1 to produce
a first resonance region having a specific shape that corresponds
to a desired sensitivity, the first NMR tool including a first
measurement circuit that measures the induced signals; circuitry
that determines a decay loss factor from the measured induced
signals; and circuitry that derives the flow velocity from the
determined decay loss factor.
59. The apparatus of claim 58, wherein the first NMR tool is
configured so that the first resonance region is in the shape of a
thin, long cylindrical shell.
60. The apparatus of claim 58, wherein the first NMR tool is
configured so that the first resonance region is a flattened
torus-shaped region.
61. The apparatus of claim 58, wherein the first NMR tool is
configured so that the first resonance region is
saddle-point-shaped.
62. The apparatus of claim 58, wherein the first measurement
circuit measures amplitude of the induced signals.
63. The apparatus of claim 58, wherein the induced signals are
produced from spin echoes, each spin echo having an echo shape and
phase, and the circuitry that determines decay loss factor analyzes
the echo shapes and echo phases in time domain to determine the
decay loss factor.
64. The apparatus of claim 58, wherein the induced signals are
produced from spin echoes, each spin echo having an echo shape and
phase, and the circuitry that determines decay loss factor analyzes
the echo shapes and echo phases in frequency domain to determine
the decay loss factor.
65. The apparatus of claim 58, wherein the induced signals are
produced from spin echoes, each spin echo having an echo shape and
phase, the apparatus further comprising circuitry that determines
flow direction by analyzing the echo shapes in frequency
domain.
66. The apparatus of claim 58, wherein the induced signals are
produced from spin echoes, each spin echo having an echo shape and
phase, the apparatus further comprising circuitry that determines
flow direction by analyzing the echo shapes in time domain.
67. The apparatus of claim 58, wherein the circuitry that derives
flow velocity also distinguishes diffusion from induced fluid
flow.
68. The apparatus of claim 59, further comprising: a second NMR
tool that provides a second static magnetic field to polarize a
second substantial portion of the formation that is subject to the
second static magnetic field, and provides a second oscillating
magnetic field to a second specific part of the polarized portion
to induce the production of measurable signals in the second
specific part, the second oscillating magnetic field being provided
in accordance with specific field maps B.sub.O and B.sub.1 to
produce a second resonance region having a specific shape that
corresponds to a desired sensitivity different than that of the
first NMR tool, the second NMR tool including a second measurement
circuit that measures the induced signals in the second specific
part.
69. The apparatus of claim 68, wherein the first and second NMR
tools are included within a drill string and NMR measurements of
flow velocity may be made while drilling of the wellbore
occurs.
70. The apparatus of claim 68, wherein the first and second NMR
tools are attached to a drill string within the wellbore, the
apparatus further comprising: first and second packer modules
attached to the drill string, the first NMR tool being located on
the drill string between the first and second packer modules.
71. The apparatus of claim 58, wherein the first NMR tool is
attached to a drill string within the wellbore, the apparatus
further comprising: first and second packer modules mounted on the
drill string such that the first NMR tool is mounted between the
first and second packer modules; and a pressure measurement probe
that can measure pressure at an interface between a formation and a
mudcake, the pressure measurement probe being mounted on the drill
string between the first and second packer modules.
72. The apparatus of claim 71, wherein the circuitry that derives
the flow velocity from the determined decay loss factor derives a
horizontal component of flow velocity from the measurable signals
induced by the first NMR tool and a vertical component of flow
velocity from the measurable signals induced by the second NMR
tool, the apparatus further comprising: circuitry that derives a
measurement of permeability from the horizontal component, the
vertical component and local gradient pressure measurements from
the pressure measurement probe.
73. The apparatus of claim 58, wherein the NMR tool is included
within a drill string and NMR measurements of flow velocity may be
made while drilling of the wellbore occurs.
Description
FIELD OF THE INVENTION
[0001] 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
[0002] 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 pores of the formation--is
therefore, an important factor in determining whether a specific
well site is commercially viable.
[0003] 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 (B.sub.O) 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 T.sub.1, 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 B.sub.O has been
established.
[0004] Next, a series of radio frequency (RF) pulses are produced
so that an oscillating magnetic field B.sub.1 is applied. The first
RF pulse (referred to as the 90.degree. pulse) must be strong
enough to rotate the magnetization from B.sub.O substantially into
the transverse plane (i.e., transverse magnetization). The rotation
angle is given by:
.alpha.=B.sub.1.gamma.t.sub.p (1)
[0005] and is adjusted, by methods known to those skilled in the
art, to be 90.degree. (where t.sub.p is the pulse length and
.gamma. is the gyromagnetic ratio--a nuclear constant). Additional
RF pulses (referred to as 180.degree. pulses where
.alpha.=180.degree.) 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.degree. and 180.degree. in the
center of this region.
[0006] 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.degree. pulse. The spin-lattice relaxation
time (T.sub.1) 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 (T.sub.2) is the time constant for the transverse
magnetization to return to its thermal equilibrium value which is
zero. Typically, T.sub.2 distributions are measured using a pulse
sequence such as the CMPG pulse sequence described above. In
addition, B.sub.O is typically inhomogeneous and the transverse
magnetization decays with the shorter time constant T.sub.2*,
where: 1 1 T 2 * = 1 T 2 + 1 T ' ( 2 )
[0007] In the absence of motion and diffusion, the decay with
characteristic time T' is due to B.sub.O inhomogeneities alone. In
this case, it is completely reversible and can be recovered in
successive echoes. The amplitudes of successive echoes decay with
T.sub.2. Upon obtaining the T.sub.2 distributions, other formation
characteristics, such as permeability, may be determined.
[0008] A potential problem with the T.sub.2 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.
[0009] Moreover, it also is known that T.sub.2 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, Jun.
15-18, 1997, describes the measurement of bound fluid volume by
relating each relaxation time 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 T.sub.2 distribution and pore size.
[0010] 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 T.sub.2 distributions, created from
NMR experiments, which represent pore size distributions. Finally,
permeability is related to the T.sub.2 data. This way to determine
permeability has several drawbacks and is therefore sometimes
inapplicable.
[0011] Typically T.sub.2 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 T.sub.2.sup.max. 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 T.sub.2 distributions do not represent pore size
distributions, e.g., hydrocarbons in water wet rocks change the
correlation between T.sub.2 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 relatively weak correlation. In carbonates,
these formulae breakdown because of the formations' complex pore
shapes.
[0012] 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.
[0013] For at least the foregoing reasons, it is an object of the
present invention to provide apparatus and methods for determining
flow velocity utilizing NMR techniques.
[0014] It is a still further object of the present invention to
provide methods for determining permeability utilizing NMR
measurements of flow velocity.
[0015] It is an even further object of the present invention to
provide methods for determining 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.
SUMMARY OF THE INVENTION
[0016] These and other objects of the invention are accomplished in
accordance with the principles of the invention by providing
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. The preferred embodiments include methods
and apparatus in which flow velocity is determined without
knowledge of T.sub.2 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 T.sub.2, 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.
[0017] In other preferred 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 preferred embodiments, an
encoding pulse is substituted for the traditional 90.degree. pulse,
and adiabatic pulses are substituted for the traditional
180.degree. pulses. These techniques are advantageous if the
B.sub.O gradient is small, e.g., in the case of a B.sub.O saddle
point, because only an inhomogeneous field B.sub.1 is required,
rather than a B.sub.O gradient.
[0018] The methods and apparatus 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 may be 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.
[0019] In addition, the NMR techniques 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 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 the present
invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] 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;
[0021] 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;
[0022] 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;
[0023] 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;
[0024] 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;
[0025] 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;
[0026] FIG. 5 is a schematic diagram of another embodiment of an
NMR logging apparatus in accordance with the principles of the
present invention;
[0027] 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;
[0028] FIG. 7 is a flow chart illustrating steps for determining
flow velocity in accordance with the principles of the present
invention; and
[0029] 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
[0030] 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).
[0031] 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
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.
[0032] 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 B.sub.O or B.sub.1 fields instead of switched
gradients, and therefore, it works for "inside out" NMR conditions
where measurements are made outside the magnet configuration.
[0033] 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.
[0034] 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.
[0035] 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.
[0036] The loss of the I-th echo can be characterized by a loss
factor: .lambda..sub.i=A.sub.i/A.sup.0.sub.i, where A.sup.0.sub.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 .lambda. (vectors
herein are denoted with the character " "). This requires that
several measurements be made with varying velocities. Let the
measured response vector be S.sub.v ={A.sub.1, . . . , A.sub.n} and
assume a measured response, such as for v=0, produces a response
vector S.sub.0 ={A.sup.0.sub.1, . . . , A.sup.0.sub.n}, then the
characteristic loss factor vector is directly given by .lambda.
={A.sub.1/A.sup.0.sub.1, . . . , A.sub.n/A.sup.0.sub.n}. Thus, for
a given measurement apparatus with known field maps and a fixed
pulse sequence, a lookup table of .lambda. (V) can be calculated
from which v can be derived.
[0037] The methods and apparatus of the present invention utilize
an excitation pulse in accordance with field maps B.sub.O and
B.sub.1 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 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 B.sub.0 like that employed in the
MRIL.RTM. tool of the Numar Corporation.
[0038] 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. Pat. No. 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 B.sub.1 field is present, it is also
possible to utilize a saddle-point-shaped B.sub.O at resonance.
[0039] In addition to determining flow velocity v from the loss
factor .lambda..sub.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 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 .lambda. (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 T.sub.2 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.
[0040] 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).
[0041] 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.
[0042] 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.degree. 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
configuration shown in FIG. 5 and the corresponding text below) and
hydraulic communication is made between probes 206 and the
formation.
[0043] 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.
[0044] 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, 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.
[0045] 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).
[0046] 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 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.
[0047] 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.
[0048] 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 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.
[0049] 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.
[0050] 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 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.
[0051] 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 rA(t)
and a change in resonance frequency .delta..omega. also is a
function of one parameter: G .multidot.r =.delta..omega..
Therefore, every change in resonance frequency corresponds to a
particular displacement and .delta..omega..sub.i at the time
I*t.sub.e of echo I can be related to an average velocity
r/(I*t.sub.e). Every echo I of a given echo train thus represents
an experiment with a different "mixing" time (I*t.sub.e) 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.
[0052] For example, an analysis of the echo shape f(t) (or echo
spectrum f(.omega.)) 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 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.
[0053] 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*t.sub.e) or echo
number (2*I) were doubled). FIGS. 6a-6e show that, 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.
[0054] 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).
[0055] 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 B.sub.O and
B.sub.1 to produce a resonance region having a specific shape
dictated by the desired motion sensitivity. The 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.
[0056] 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).
[0057] 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 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.
[0058] Many of the previously described NMR measurements of flow
velocity rely on a relatively high gradient in B.sub.O. 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 B.sub.1 is present. There are various known
techniques for applying magnetic field gradients to produce
stimulated echoes, however, those techniques all require an
inhomogeneous B.sub.1 encoding pulse followed by the application of
a homogeneous B.sub.1 refocusing pulse and homogeneous B.sub.1
reading pulses. Inside out NMR saddle-point tools naturally produce
the required strongly inhomogeneous B.sub.1 field (from the RF
coil), but the substantially homogeneous B.sub.1 field simply is
not achievable.
[0059] The refocusing/reading pulse may, in accordance with the
present invention, be accomplished with the inhomogeneous B.sub.1
field by utilizing adiabatic methods as shown in FIG. 8. For
example, following 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.
[0060] 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 B.sub.O 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.
[0061] 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
provide immediate feedback. One particularly useful parameter that
may be determined is a direct measurement of permeability based on
Darcy's formula which states: 2 v = 1 K * grad * p ( 3 )
[0062] where v represents seepage velocity, .mu. 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 K.sub.h and
K.sub.v (i.e., the horizontal component and the vertical component,
respectively).
[0063] By applying the NMR measurements described above to
determine local fluid velocity, values for K.sub.h and K.sub.v 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, K.sub.v=.mu.v.sub.z/dp/dz. Assuming the fluid
viscosity .mu. is known, dp/dz easily may be obtained through the
use of pressure monitor probes, and because v.sub.z is determined
based on one of the above-described NMR measurements, K.sub.v 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 fluid velocity (as described above) provides K.sub.h
(based on the derivation that
K.sub.h=.mu.v.sub..theta.r.sub.w/dp/d.theta- .). Once K.sub.h and
K.sub.v 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.
[0064] 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 r.sub.d 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: 3 S = ( K .infin. K d - 1 ) ln ( r d r w ) ( 4 )
[0065] where r.sub.w is the wellbore radius, and K.sub..infin. and
K.sub.d are the permeabilities of the virgin formation and damaged
zones, respectively. Accordingly, once r.sub.d is determined from
for example, array resistivity logs, a detailed, depth-resolved
model of the damaged zone can be constructed and a value of the
skin may be determined.
[0066] 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.
[0067] 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.
[0068] When, for reasons of well control, safety or precision in
measurement, it is desirable to adjust the pressure in the entire
wellbore, 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.
[0069] 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 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.
* * * * *