U.S. patent application number 14/528568 was filed with the patent office on 2016-05-05 for apparatus and method for simultaneously obtaining quantitative measurements of formation resistivity and permittivity in both water and oil based mud.
The applicant listed for this patent is Weatherford Technology Holdings, LLC. Invention is credited to Jiefu Chen, Shanjun Li.
Application Number | 20160124106 14/528568 |
Document ID | / |
Family ID | 55130480 |
Filed Date | 2016-05-05 |
United States Patent
Application |
20160124106 |
Kind Code |
A1 |
Li; Shanjun ; et
al. |
May 5, 2016 |
APPARATUS AND METHOD FOR SIMULTANEOUSLY OBTAINING QUANTITATIVE
MEASUREMENTS OF FORMATION RESISTIVITY AND PERMITTIVITY IN BOTH
WATER AND OIL BASED MUD
Abstract
An apparatus and method for simultaneously obtaining
quantitative measurements of vertical and horizontal resistivity
and permittivity formation parameters by firing, using at least one
transmitter in each of a horizontally and vertically polarized
array on opposite sides of a drill collar, signals in the direction
of a downhole formation, the fired signals from the transmitters in
the arrays being fired simultaneously and engaging the downhole
formation. The apparatus and method continues by receiving, using
at least one receiver in each of the arrays, signals associated
with the fired signals after the fired signals have engaged the
downhole formation, where the received signals represent apparent
formation data. The apparatus and method further involves
determining, using the measured apparent formation data, the true
formation data including one or more vertical and horizontal
formation parameters.
Inventors: |
Li; Shanjun; (Katy, TX)
; Chen; Jiefu; (Cypress, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Weatherford Technology Holdings, LLC |
Houston |
TX |
US |
|
|
Family ID: |
55130480 |
Appl. No.: |
14/528568 |
Filed: |
October 30, 2014 |
Current U.S.
Class: |
324/338 |
Current CPC
Class: |
G01V 3/30 20130101; G01V
1/30 20130101; E21B 47/01 20130101; G01V 1/50 20130101; G01V 3/28
20130101; G01V 3/104 20130101; G01V 99/005 20130101; G01V 11/002
20130101; E21B 49/00 20130101; G01V 3/38 20130101; G01V 5/045
20130101; E21B 17/1078 20130101 |
International
Class: |
G01V 3/30 20060101
G01V003/30; G01V 3/38 20060101 G01V003/38 |
Claims
1. A method for measuring formation properties downhole, the method
comprising: firing, using at least one transmitter in each of a
horizontally and vertically polarized array on opposite sides of a
drill collar, signals in the direction of a downhole formation, the
fired signals from the transmitters in the arrays being fired
simultaneously and engaging the downhole formation; receiving,
using at least one receiver in each of the arrays, signals
associated with the fired signals after the fired signals engage
the downhole formation, the received signals representing apparent
formation measurement data; determining, using the apparent
formation measurement data, true formation measurement data; and
obtaining, using the true formation measurement data, one or more
vertical and horizontal formation parameters.
2. The method of claim 1, wherein the vertical and horizontal
formation parameters include the vertical and horizontal
resistivity and permittivity of the downhole formation.
3. The method of claim 1, wherein the apparent formation
measurement data includes the phase and attenuation of the apparent
formation measurement data.
4. The method of claim 1, wherein determining true formation
measurement data includes: obtaining, simulated formation
measurement data; comparing, the simulated formation measurement
data with the apparent formation measurement data; updating, if the
difference between the simulated formation measurement data and the
apparent formation measurement data exceeds a threshold, true
formation measurement data; and outputting, if the difference
between the simulated formation measurement data and the true
formation measurement data does not exceed the threshold, the true
formation measurement data.
5. The method of claim 1, wherein engaging the downhole formation
comprises inducing signals into the downhole formation.
6. The method of claim 1, wherein firing, using at least one
transmitter in each of a horizontally and vertically polarized
array, includes firing high frequency signals.
7. The method of claim 6, wherein high frequency signals comprise
signals having a frequency between 10 MHz and 20 GHz.
8. The method of claim 1, wherein the horizontally and vertically
polarized arrays are disposed on opposite sides of a centralizer
disposed on the drill string.
9. The method of claim 1, wherein determining the true formation
measurement data includes updating the true formation measurement
data.
10. The method of claim 1, wherein the plurality of transmitters
and receivers are filled with an epoxy.
11. A downhole tool, comprising: a drill string; a drill collar
disposed on the drill string; each of a horizontally and vertically
polarized array disposed on opposite sides of the drill collar and
connected by one or more wires, the horizontally and vertically
polarized arrays including a plurality of transmitters and
receivers; wherein, when the one or more wires are energized by a
source the one or more wires simultaneously cause a first
transmitter of the plurality of transmitters in each of the arrays
to fire signals in the direction of a downhole formation, the fired
signals from each of the first transmitters engaging the downhole
formation; wherein, the one or more wires are energized by the
source to cause a first and second receiver in each of the arrays
to receive signals associated with the signals fired from the first
transmitters after the fired signals have engaged the downhole
formation, the first receivers in each array being disposed between
the first transmitters and second receivers, the received signals
representing apparent formation data; wherein, when the one or more
wires are energized by the source the one or more wires
simultaneously cause a second transmitter of the plurality of
transmitters in each of the arrays to fire signals in the direction
of the downhole formation, the fired signals from each of the
second transmitters engaging the downhole formation; wherein, the
one or more wires are energized to cause the first and second
receivers in each of the arrays to receive signals associated with
the signals fired from the second transmitters after the fired
signals have engaged the downhole formation, the second receivers
in each array being disposed between the first receivers and the
second transmitters, the received signals representing apparent
formation measurement data; wherein, true formation measurement
data is determined using the apparent formation measurement data;
and wherein, one or more vertical and horizontal formation
parameters are obtained using the true formation measurement
data.
12. The downhole tool of claim 11, wherein the vertical and
horizontal formation parameters include the vertical and horizontal
resistivity and permittivity of the downhole formation.
13. The downhole tool of claim 11, wherein the apparent formation
measurement data includes the phase and attenuation of the apparent
formation measurement data.
14. The downhole tool of claim 11, wherein the true formation
measurement data is determined by obtaining simulated formation
measurement data by using one or more processors to simulate or
numerically model the interaction between the tool and the
formation within the wellbore; wherein after the simulated
formation measurement data is obtained the one or more processors
compare the simulated formation measurement data with the apparent
formation measurement data; wherein, if the one or more processors
determine that the difference between the simulated formation
measurement data and the apparent formation measurement data
exceeds a threshold the true formation measurement data is
determined; and wherein, if the one or more processors determine
that the difference between the simulated formation measurement
data and the true formation measurement data does not exceed the
threshold, the true formation measurement data is output.
15. The downhole tool of claim 11, wherein engaging the downhole
formation comprises inducing signals into the downhole
formation.
16. The downhole tool of claim 11, wherein the first and second
transmitters of the plurality of transmitters in each of the
horizontally and vertically polarized arrays fires high frequency
signals.
17. The downhole tool of claim 16, wherein high frequency signals
comprise signals having a frequency between 10 MHz and 20 GHz.
18. The downhole tool of claim 11, wherein the horizontally and
vertically polarized arrays are disposed on opposite sides of a
centralizer disposed on the drill string.
19. The downhole tool of claim 11, wherein when the true formation
measurement data is determined the true formation measurement data
is updated.
20. The downhole tool of claim 11, wherein the plurality of
transmitters and receivers are filled with an epoxy.
Description
BACKGROUND OF THE DISCLOSURE
[0001] During the exploration of oil and gas, measuring the
resistivity and permittivity of a formation downhole can provide
important data for geologist and petro physicist to evaluate
formation property, such as whether a formation contains water or
hydrocarbons. Due to deposition, fractures, and the lamination of
layers within a formation, etc., formations downhole will typically
exhibit some form of anisotropy. The resistivity and permittivity
anisotropy of a formation downhole can represent this formation
anisotropy. The anisotropy has large effects on the resistivity and
permittivity measurements, which will affect the accuracy of
formation evaluation.
[0002] Anisotropy is commonly modeled using transverse isotropy
(TI). A formation will exhibit TI-anisotropy when it has an axis of
symmetry such that along any direction parallel (or transverse) to
this axis the material properties of the formation are the same.
However, between the axis of symmetry and a direction perpendicular
to the axis of symmetry, one will see a material property
difference.
[0003] Electromagnetic tools used in wireline and measurement while
drilling (MWD) applications are typically used for measuring
formation resistivity and dielectric permittivity. However, some
electromagnetic tools, such as resistivity and permittivity
measurement tools, used in wireline haven't used in MWD.
[0004] Also, although these electromagnetic tools used in MWD are
capable of taking measurements while drilling, these tools are
currently focused on measuring TI-anisotropy of a formation in one
direction relative to the axis of the tool, and cannot measure the
anisotropy of a formation in multiple directions
simultaneously.
[0005] Further, another limitation of many electromagnetic tools
which can operate in water base-mud is that they cannot operate in
oil based mud due to the non-conductive nature of some oil based
mud. Therefore, having the ability to operate in both oil based mud
and water base mud environment is one advantage some
electromagnetic tools have over others. By operating electrical
electromagnetic tools using higher frequencies (in the range of
hundreds of Megahertz to Gigahertz), these tools are better able to
take measurements in oil based mud as well as in water base
mud.
[0006] It is therefore desirable to have an apparatus and method
for taking quantitative measurements of formation parameters, such
as resistivity and permittivity, in multiple directions
simultaneously. Moreover, it is also desirable to be able to take
quantitative measurements of the formation parameters in both water
based and oil based mud. The subject matter of the present
disclosure is directed to overcoming, or at least reducing the
effects of, one or more of the problems set forth above.
SUMMARY OF THE DISCLOSURE
[0007] The present disclosure involves an apparatus and method for
simultaneously obtaining quantitative measurements of vertical and
horizontal resistivity and permittivity by firing, using at least
one transmitter in each of a horizontally and vertically polarized
array on opposite sides of a drill collar, signals in the direction
of a downhole formation, the fired signals from the transmitters in
the arrays being fired simultaneously and engaging the downhole
formation.
[0008] The apparatus and method continues by receiving, using at
least one receiver in each of the arrays, signals associated with
the fired signals after the fired signals have engaged the downhole
formation, where the received signals represent apparent formation
measurement data.
[0009] The apparatus and method further involves determining, using
the measured apparent formation data, the true formation data
including one or more vertical and horizontal formation
parameters.
[0010] The foregoing summary is not intended to summarize each
potential embodiment or every aspect of the present disclosure.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] FIG. 1 illustrates a downhole tool disposed in a wellbore
according to the present disclosure.
[0012] FIGS. 2A-2B illustrate vertical and horizontal antenna
elements according to the present disclosure.
[0013] FIG. 3 illustrates exemplary antenna arrays according to the
present disclosure.
[0014] FIGS. 4A-4D illustrate exemplary combinations of antenna
array configurations according to the present disclosure.
[0015] FIGS. 5A-5C illustrate side and cross-sectional views of a
stabilizer according to the present disclosure.
[0016] FIG. 6 illustrates a method for simultaneously obtaining
quantitative vertical and horizontal formation parameters according
to the present disclosure.
[0017] FIG. 7 illustrates a method for determining true formation
measurement data according to the present disclosure.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0018] Overview of the Apparatus
[0019] FIG. 1 illustrates a downhole tool 100 having a cylindrical
body disposed in a wellbore 114 according to the present
disclosure. As shown, the downhole tool 100 includes a drill string
113 being disposed in a wellbore 114 from a drilling rig 110 and
has a bottom hole assembly (BHA) including a drill collar 125
disposed thereon. The rig 110 also has draw works and other systems
for controlling the drill string 113 as it advances in and out of
the wellbore 114. The rig also has mud pumps (not shown) that
circulate drilling fluid or drilling mud through the drill string
113.
[0020] As shown, the drill collar 125 of the downhole tool (100)
has an electronics section 130, a mud motor 135, and an instrument
section 140. Drilling fluid flows from the drill string 113 and
through the electronics section 130 to the mud motor 135. Powered
by the pumped fluid, the motor 135 imparts torque to the drill bit
145 to rotate the drill bit 145 and advance the wellbore 114.
[0021] Also as shown, one or more centralizers 115 may be disposed
on a drill collar or on the drill string 113, and may act as a
stabilizer for stabilizing the drill string 113 in the wellbore
114. Further as will be discussed below, one or more
electromagnetic antenna arrays 112 can be disposed on the
centralizers 115. However, as not to limit the antenna arrays 112
to being disposed on the centralizers 115, the arrays may be
disposed anywhere on the BHA, preferably on the drilling collar
within the wellbore 114. Surface equipment 105 having an up hole
processing unit (not shown) may also obtain and process formation
measurement data from the electromagnetic antenna arrays disposed
on the centralizers 115. Typically, the surface equipment 105 may
communicate data with the electromagnetic antenna arrays and/or
electronics section 130 using telemetry systems known in the art,
including mud pulse, acoustic, and electromagnetic systems.
[0022] Referring now to FIGS. 2A-2B, vertical and horizontal slot
antenna elements (200 and 205) are illustrated according to the
present disclosure. As discussed below, each slot antenna element
(200 and 205) may be used for both transmitting and receiving
electrical signals into a wellbore 114. Also, more than one slot
antenna (200 and 205) may be included in the electromagnetic
antenna arrays 112 discussed above.
[0023] As will be appreciated by those skilled in the art, this
disclosure is not limited to a particular type of slot antenna (200
and 205) for transmitting and/or receiving electrical signals, as
any slot antenna known in the art for transmitting and receiving
electrical signals may be used (e.g., horn antennas including a
waveguide, etc.).
[0024] Also, although the present disclosure is indifferent to the
type of slot antenna (200 and 205) that may be used, in order for
the tool to operate in oil based mud, the slot antenna (200 and
205) must operate using higher frequencies. For example, in one
aspect of the invention, operating slot antennas 200 may use a
frequency range between 10 MHz (Megahertz) and 20 GHz
(Gigahertz).
[0025] In one example, the openings of the slot antenna elements
(200 and 205) may be filled with an epoxy or other non-conducting
filler. This epoxy serves to protect the slot antenna elements (200
and 205) during logging while drilling operations. Further, the
shape of the slot antenna elements (200 and 205) is not limited to
having rectangular apertures as shown, as different antenna
aperture designs may be incorporated.
[0026] Now referring to FIG. 2A, because slot antenna element 200
is shown oriented vertically with respect to the Z axis (i.e.,
magnetically polarized in a vertical direction) it is considered to
be vertically polarized. Thus, the vertically polarized slot
antenna elements 200 can be regarded as having vertical magnetic
moments. Furthermore, as will be described further below, because
electrical current will traverse the vertically polarized slot
antenna elements 200 along the X/Y axis, the vertically polarized
slot antennas 200 are considered to have horizontal electric
moments (Eh). The horizontal or vertical orientations of the
antenna elements are with respect to the axes of the drill string
113.
[0027] Likewise as shown in FIG. 2B, because the slot antenna
element 205 is shown oriented horizontally along the X/Y axis, it
is considered to be horizontally polarized. Also, because the
magnetic polarization of horizontally polarized slot antenna 205 is
along the X/Y axis, horizontally polarized slot antenna elements
205 can be regarded as having a horizontal magnetic moment. Also as
will be discussed below, because electrical current will flow
through the horizontally polarized slot antennas 205 in a direction
orthogonal to the direction of its magnetic polarization (i.e.,
along the Z axis), the horizontally polarized slot antenna elements
205 are considered to have a vertical electric moment (Ev).
[0028] FIG. 3 illustrates four exemplary electromagnetic antenna
arrays 112 according to the present disclosure. In one example,
each antenna array is composed of four slot antenna elements (200
and 205), using two slot antenna elements as transmitters for
transmitting (T1 and T2) or (T3 and T4), and using two slot antenna
elements as receivers for receiving (R1 and R2) or (R3 and R4).
[0029] Also, slot antenna transmitters T1 and T3 are
interchangeable depending on which antenna array (305-320) is
referred to as the first or second array. Likewise, slot antenna
transmitters (T2 and T4) are also interchangeable. For similar
reasons receivers (R1 and R3) and (R2 and R4) are similarly
interchangeable.
[0030] Referring again to FIG. 3, each of the antenna arrays 112
has a different slot antenna element (200 and 205) configuration.
In one example according to the present disclosure, a vertically
polarized vertical array (VPVA) 305 may be composed of four
vertically polarized slot antenna elements (200). In another
example, a horizontally polarized horizontal array (HPHA) 310 is
shown composed of four horizontally polarized slot antenna elements
(205). In yet another example, as shown, a vertically polarized
horizontal array (VPHA) 315 is shown being composed of four
vertically polarized slot antenna elements (200). Also, in another
example, a horizontally polarized vertical array (HPVA) 320 is
shown being composed of four horizontally polarized slot antenna
elements (205).
[0031] As will be described below, each of these antenna arrays
(112) (e.g., 305-320) may be used in combination with another
antenna array (305-320) on an opposite pad (not shown) of the
downhole tool centralizer 115, or opposite side of the drill
collar. Thus, considering the rotation of the tool in the wellbore
114, the two antenna arrays (305-320) can be regarded as one tool
having an equivalent, vertical and horizontal, electric
moments.
[0032] That is, as the tool rotates around wellbore 114, because
the antenna arrays (305-320) are disposed on opposite sides of the
tool (100), the antenna arrays (305-320) can simultaneously be used
to detect bi-axial properties of the downhole formation such as the
resistivity and permittivity of the formation in both the vertical
direction and at all azimuthal angle positions within the wellbore
(114).
[0033] As described above, and as will be described below, each
antenna array (305-320) is disposed on opposite sides of the tool's
centralizer (115), and will be used to transmit electrical signals
into the wellbore (114) and receive signals associated with those
transmitters, after the signals have engaged the formation
downhole. One purpose for having vertical and horizontal polarities
of the antenna arrays (305-320) is so that, based on the polarities
of the antenna elements (200 and 205), the downhole tool may
simultaneously take measurements in both the vertical and
horizontal directions within the wellbore (e.g. Z and X/Y axes,
respectively).
[0034] To further illustrate the possible antenna array (305-320)
combinations, we now refer to FIGS. 4A-4D. As shown, four exemplary
combinations of antenna array (305-320) configurations may be used
according to the present disclosure. With reference to FIG. 4A, a
HPVA 320 is shown in combination with a VPHA 315. Because in this
example the polarity of the slot antennas elements (205) of the
HPVA 320 is in the horizontal direction, the polarity of the
measured data will be in the horizontal direction along the X/Y
axis relative to the tool drill collar (125). Also, because the
slot antenna elements (200) of the VPHA 315 of FIG. 4A are
vertically polarized, the polarity of the data will be in the
vertical direction, along the Z axis relative to the drill collar
(125).
[0035] In another example referring to FIG. 4B, an HPVA 320 is
shown in combination with a VPVA 305. Also, in another example
referring to FIG. 4C, a VPVA 305 may be in combination with a HPHA
310, and in yet another example referring to FIG. 4D, a HPHA 320
may be in combination with a VPHA 310. In each of these examples,
as described above with reference to FIG. 4A, the direction of the
data measured by individual slot antennas (200 and 205) will vary
with the direction of the polarization of each slot antenna (200
and 205).
[0036] Now that we have discussed slot antennas (200 and 205) and
the combinations of electromagnetic array antennas (305-320) that
may be disposed on the centralizers (115) of the downhole tool
(100), the disclosure will now illustrate how the electromagnetic
arrays (305-320) may be disposed on the one or more centralizers
(115).
[0037] As shown in FIGS. 5A-5C, side and cross-sectional views of a
centralizer 115 is shown according to the present disclosure.
Referring to FIG. 5A, a VPHA 310 is shown disposed on a centralizer
115. As shown, the VPHA 310 is placed in the center of the
centralizer's 115 pad 505, although the placement of the array on
the pad 505 is not limited to the center. In one example, the
centralizer 115 may have many different sizes or designs.
[0038] Also, as shown in FIG. 5B, the centralizer 115 has four pads
displaced around the centralizer 115, being separated by
90.degree.. The opposite sides of the centralizer 115 is better
illustrated by referring to the cross sectional view of the
centralizer 115 in FIG. 5B. As shown, the centralizer 115 has four
sides separated by 90.degree.. In one example, opposite sides of
the centralizer 115 are illustrated by sides 505. In this example,
an antenna array (305-320) may be on any side of the centralizer
115, with any other antenna array having opposite polarity (e.g.,
305-320) being on the opposite side (i.e., separated by
180.degree.). Also, although the tool (100) has been described
above having a centralizer with four sides, the tool is not limited
to four sides. The tool (100) can have many sides which would
create various angles, as long as the antenna arrays (305-320) are
on sides that oppose each other.
[0039] Also as shown in FIG. 5A, a wire 515 carrying electrical
current is connected to the VPHA 310 in the (FRONT) pad of the
centralizer 115, in the direction of the electric moment (Ev) of
the vertically polarized slot antenna elements (205) (see FIG. 2A).
The wire 515 is connected in a way that causes the transmitters and
receivers (not shown) of the VPHA 310 to repeatedly transmit
signals in the direction of the wellbore (114), and repeatedly
receive signals associated with the transmitted signals after they
have engaged the wellbore (114).
[0040] The transmitted and received signals are electromagnetic
waves or signals that engage the wellbore (114) by inducing signals
into the formation. Formation properties can then be determined by
measuring or analyzing the electromagnetic waves or signals
associated with the transmitted signals. The wire 515 may be one or
more wires, and is also connected to the second receiver array
(305-320) on the opposite (or BACK) side of the centralizer 115
(e.g., the HPVA 320 shown in FIG. 5C), forming a circuit that may
be energized by an electrical source (not shown) from within the
electronics section (130) or instrument section (140) of the tool
(100). The source may be a battery or other source capable of
driving electrical current, and may be caused to drive current by
one or more processors in the electronics section (130) or
instrument section (140) of the tool (100) (not shown).
[0041] The electrical current in the wire 515 traverses the VPHA
310 and the HPVA 320 in the direction of their respective electric
moments (Ev or Eh) (see FIG. 2B), in a way that causes the
transmitters and receivers (not shown) within the VPHA 310 and the
HPVA 320 to transmit and receive signals. The diagrams in FIGS.
5A-5C are only conceptual in nature, used to illustrate example
configurations and the operation of the system. The figures
disclosed are not intended to limit the mechanical configurations,
antenna array (305-320) configurations, or circuit designs of the
present disclosure.
[0042] Now that the components of the system and various example
configurations of the antenna arrays with the centralizer 115 have
been illustrated, the method of obtaining quantitative measurements
of resistivity and permittivity will now be described.
[0043] FIG. 6 illustrates a method for simultaneously obtaining
quantitative vertical and horizontal formation parameters according
to the present disclosure. Referring to step 600 and using the
example transmitters and receivers of FIG. 3 for reference, one or
more processors in the electronics section (130) or instrument
section (140) of the tool (100) may cause the one or more wires
(515) to be energized by an electrical source, thereby causing
transmitters (T1 and T2) in one antenna array (i.e., one of the
four antenna arrays 305-320) to transmit signals in the direction
of the wellbore (114).
[0044] After the transmitted signals have engaged the wellbore
(114), at step 605 the receivers (R1 and R2) will receive signals
associated with the transmitted signals. Also, simultaneously with
transmitters (T1 and T2) at step 600, transmitters (T3 and T4)
within the second antenna array (305-320) on the opposite side of
the centralizer 115 (as described in FIGS. 5A-5C) will transmit
signals in the direction of the wellbore (114), and the associated
signals will be received at step 605 by receivers (R3 and R4) in
the second antenna array. The received signals represent apparent
quantitative formation measurement data (i.e., measured apparent
formation data) and may be used to determine quantitative formation
properties such as the resistivity and permittivity of the
formation.
[0045] As described above with reference to FIGS. 5A-5C, the two
antenna arrays disposed on the opposite sides of the centralizer
115 may include any of the four combinations discussed above with
reference to FIG. 3 (305-320); however, if one side of the
stabilizer pad 505 has a vertically polarized array (e.g., array
305 or 315) the opposite pad will have a horizontally polarized
array (e.g., array 310 or 320) disposed thereon. Accordingly, the
quantitative formation properties that are determined will be
reflective of the formation properties in both the vertical and
horizontal directions, relative to the drill collar 125.
[0046] Also, considering the rotation of the tool (100) in the
wellbore, both the horizontal and vertical arrays (305-320) on each
side of the centralizer 115 can be regarded as one tool (i.e., one
electromagnetic antenna) having equivalent vertical and horizontal
magnetic moments, as described with reference to FIGS. 2A-2B. As a
result, while the tool rotates within the wellbore (114), the tool
can be used to detect the formation properties at all azimuthal
angles within the wellbore (114).
[0047] Referring again to the method illustrated in FIG. 6, once
the signals associated with the transmitted signals have been
received at step 605, they may be processed using one or more
processors (not shown) associated with the surface equipment (105),
electronics section (130), or instrument section (140) to obtain
the compensated voltage (Vcomp) of the quantitative formation data.
The one or more processors (not shown) may communicate with memory
having instructions stored thereon for enabling the one or more
processors to process the signals.
[0048] Using methods known in the art, the compensated voltage
Vcomp can then be used to determine the phase and attenuation.
Computations that can be used for determining the Vcomp,
attenuation, and phase difference along the vertical and horizontal
planes of the wellbore (114) formation are shown below:
V comp = V T 1 R 2 V T 1 R 1 V T2 R 1 V T 2 R 2 , AT = 20 log 10 (
V comp ) , PD = ATAN 2 ( imag ( V comp ) , real ( V comp ) )
##EQU00001## V comp = V T 3 R 4 V T 3 R 3 V T 4 R 3 V T 4 R 4 , AT
= 20 log 10 ( V comp ) , PD = ATAN 2 ( imag ( V comp ) , real ( V
comp ) ) ##EQU00001.2##
[0049] As shown, the voltage compensation (Vcomp) for transmitters
(T1-T4) and receivers (R1-R4) of the two antenna arrays (305-320)
can be used to determine the attenuation ("AT" of the above
equation) and the phase difference ("PD" of the above equation) of
the wellbore (114) formation.
[0050] Because the apparent formation measurement data is only the
apparent, and not the real data, it is necessary to invert the
apparent formation measurement data for each array (i.e., each of
the vertical and horizontal arrays on opposite sides of the tool,
see FIG. 5A-5C). Using inversion, the true formation measurement
data (i.e., true vertical and horizontal, phase difference and
attenuation) may be obtained.
[0051] Referring to step 610 of FIG. 6, in one example OD or "zero
dimension" inversion as known in the art can be used to obtain the
true vertical and horizontal formation measurement data.
[0052] As discussed above, once the true phase difference and
attenuation (i.e., true formation data) has been determined using
the above equation, at step 615 using techniques known in the art,
the true formation data can be used to obtain the formation
parameters such as the resistivity and permittivity of the
formation. Such known methods for determining these parameters
include, using lookup tables or using real time processing based on
the tool response.
[0053] Referring now to FIG. 7, a method of inverting the apparent
vertical and apparent horizontal formation measurement data values
using OD inversion is illustrated according to the present
disclosure. The inversion process described below may be performed
by one or more processors (not shown) associated with surface
equipment (105) having an up hole processing unit, electronics
section (130), or instrument section (140). The inversion method
begins at step 705 by using the one or more processors to obtain
simulated formation measurement data (i.e., the simulated
attenuation and phase difference responses of the tool). The
simulated formation measurement data is the modeled response data
of the tool (100) with respect to known parameters of the formation
to which the tool is being applied. Thus, the simulated formation
measurement data can be obtained by simulating or numerically
modeling the interaction between the tool and the formation within
the wellbore 114.
[0054] After the simulated formation measurement data has been
obtained, at step 710 the simulated formation measurement data is
compared with the apparent formation measurement data determined
above. If at step 715 the difference between the simulated
formation measurement data and the apparent formation measurements
exceed a predefined threshold, the method at step 720 will
determine and incrementally update a value representing the true
formation measurement data by calculating a Jacobian matrix as is
known in the art.
[0055] Once the true formation measurement data has been determined
at step 720, and the difference between the simulated formation
measurement values and the true formation measurement data does not
exceed the predefined threshold (after repeating steps 705 through
715 using the true formation measurement data), the true formation
measurement data is output by the system as the true formation
measurement data.
[0056] However, if after the initial comparison step at 715, the
difference between the simulated formation measurement data and the
apparent formation measurement data does not exceed a predefined
threshold, the apparent formation measurement data is output as the
true formation measurement data at step 725.
[0057] As a result, the tool can be used to simultaneously obtain
quantitative measurements of the resistivity and permittivity of a
formation in both the vertical and horizontal directions within a
wellbore. Also, by rotating the drill string (113) while taking the
measurements, and transmitting using higher frequencies, the
vertical and horizontal resistivity and permittivity of the
formation may be determined at all azimuthal angles around wellbore
(114), in either oil or water based mud.
[0058] The foregoing description of preferred and other embodiments
is not intended to limit or restrict the scope or applicability of
the inventive concepts conceived of by the Applicant. It will be
appreciated with the benefit of the present disclosure that
features described above in accordance with any embodiment or
aspect of the disclosed subject matter can be utilized, either
alone or in combination, with any other described feature, in any
other embodiment or aspect of the disclosed subject matter.
[0059] In exchange for disclosing the inventive concepts contained
herein, the Applicant desires all patent rights afforded by the
appended claims. Therefore, it is intended that the appended claims
include all modifications and alterations to the full extent that
they come within the scope of the following claims or the
equivalents thereof.
* * * * *