U.S. patent application number 12/393507 was filed with the patent office on 2009-06-18 for determining wellbore position within subsurface earth structures and updating models of such structures using azimuthal formation measurements.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Jean-Michel Denichou, Soazig Leveque.
Application Number | 20090157321 12/393507 |
Document ID | / |
Family ID | 39186467 |
Filed Date | 2009-06-18 |
United States Patent
Application |
20090157321 |
Kind Code |
A1 |
Denichou; Jean-Michel ; et
al. |
June 18, 2009 |
Determining Wellbore Position Within Subsurface Earth Structures
and Updating Models of Such Structures using Azimuthal Formation
Measurements
Abstract
A method for determining structure in the Earth's subsurface
includes generating an initial model of the structure. The initial
model includes at least one layer boundary. A wellbore is drilled
along a selected trajectory through the Earth's subsurface in a
volume represented by the initial model. At least one formation
parameter is measured azimuthally along the wellbore. A distance is
determined from the wellbore at selected positions therealong to
the at least one layer boundary using the azimuthal formation
parameter measurements. The initial model is adjusted using the
determined distances. In one example, the parameter is resistivity.
In one example, the parameter is acoustic velocity.
Inventors: |
Denichou; Jean-Michel;
(Houston, TX) ; Leveque; Soazig; (Stavanger,
NO) |
Correspondence
Address: |
SCHLUMBERGER OILFIELD SERVICES
200 GILLINGHAM LANE, MD 200-9
SUGAR LAND
TX
77478
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugarland
TX
|
Family ID: |
39186467 |
Appl. No.: |
12/393507 |
Filed: |
February 26, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
11691998 |
Mar 27, 2007 |
|
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12393507 |
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Current U.S.
Class: |
702/11 ;
703/1 |
Current CPC
Class: |
G01V 11/00 20130101;
G01V 2210/6163 20130101 |
Class at
Publication: |
702/11 ;
703/1 |
International
Class: |
G01V 1/40 20060101
G01V001/40; G06F 17/50 20060101 G06F017/50; G01V 9/00 20060101
G01V009/00 |
Claims
1. (canceled)
2. (canceled)
3. (canceled)
4. (canceled)
5. (canceled)
6. (canceled)
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9. (canceled)
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11. (canceled)
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14. (canceled)
15. (canceled)
16. (canceled)
17. (canceled)
18. (canceled)
19. A system for modeling a subsurface structure of the Earth,
comprising: an instrument for measuring a formation parameter
azimuthally along a wellbore drilled through a volume of the
Earth's subsurface represented by an initial model; a processor in
signal communication with the instrument, the processor configured
to determine a distance from the wellbore to at least one formation
boundary in the volume from azimuthal measurements made by the
instrument, the processor configured to adjust the initial model
using the determined distance.
20. The system of claim 19 wherein the formation parameter is
resistivity.
21. The system of claim 19 wherein the formation parameter is
acoustic velocity.
22. The system of claim 19 wherein processor is configured to
accept at least one of seismic and electromagnetic survey data to
generate the initial model.
23. The system of claim 19 wherein the processor is configured to
accept well log data to generate the initial model.
24. The system of claim 1 wherein the processor is configured to
accept measurements of at least one additional petrophysical
parameter along the wellbore and is configured to refine the
initial model using the at least one additional petrophysical
parameter.
25. The system of claim 24 wherein the at least one petrophysical
parameter comprises at least one of acoustic velocity, natural
gamma radiation, neutron porosity, density, nuclear magnetization
transverse relaxation time, nuclear magnetization longitudinal
relaxation time, permeability and formation fluid pressure.
26. The system of claim 24 wherein the processor is configured to
accept measurement of the at least one additional petrophysical
parameter during the drilling of the wellbore.
27. The system of claim 19 wherein the processor is configured to
accept measurements of the at least one formation parameter during
the drilling of the wellbore.
28. The system of claim 19 wherein the instrument includes means
for propagating an electromagnetic wave at a first position along
the wellbore and means for measuring at least one of a phase shift
and an amplitude change of the wave at a second position along the
wellbore.
29. The system of claim 28 wherein the means for propagating and
measuring at least one of phase shift and amplitude includes
antennas having dipole moment oriented in a direction offset from a
longitudinal axis of the instrument.
30. The system of claim 19 wherein the processor is configured to
measure a seismic travel time from the Earth's surface to the
wellbore at least one position along the wellbore and adjusting the
initial model using the seismic travel time.
31. The system of claim 30 wherein the processor is configured to
calibrate the seismic travel time with respect to depth in the
subsurface using checkshot data obtained from a substantially
vertical wellbore drilled in a volume of the Earth's subsurface
represented by the initial model.
32. The system of claim 19 further comprising means for
transmitting the azimuthally measured parameter to the Earth's
surface substantially in real time and the processor is configured
to adjust the initial model substantially in real time.
33. The system of claim 32 wherein the means for transmitting
comprises at least one of an optical fiber and an electrical
conductor associated with a drill string.
34. The method of claim 14, further comprising transmitting seismic
travel time data to the surface via a wired drill pipe.
35. The method of claim 18, wherein the azimuthally measured
parameter is transmitted to the Earth's surface via a wired drill
pipe.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The invention relates generally to the field of determining
position of a wellbore within subsurface Earth formations. More
specifically, the invention relates to methods for using
azimuthally dependent formation property measurements of such
formations to more precisely locate the position of the wellbore
and to refine models of the Earth's subsurface structure.
[0003] 2. Background Art
[0004] Wellbores are drilled through subsurface Earth formations to
extract useful materials such as oil and gas that are present in
certain subsurface formations. Wellbore drilling is typically
performed in a manner to optimize the amount of oil and gas bearing
formation that is in hydraulic communication with a wellbore. Such
optimization includes drilling wellbores that are highly inclined,
even horizontal, over relatively large distances (e.g., several
kilometers) in order to cause the wellbore to be positioned within
the oil and/or gas bearing formation over a great lateral distance.
Such positioning increases the effective drainage radius of the
wellbore within the producing formation.
[0005] In order to optimize such wellbore drilling, it is known in
the art to produce a model of the structure of the Earth's
subsurface formations. Such models may be initially generated using
techniques that do not use data from within the subsurface
formations, such as seismic surveying and electromagnetic
surveying. Such surveys are interpreted to produce an initial
estimate or model of the spatial distribution of the subsurface
formations, including those that may contain oil and/or gas.
[0006] As one or more wellbores are drilled through the formations
that have been modeled using the above seismic and/or
electromagnetic surveying techniques, the model may be adjusted or
updated to reflect information obtained during or after the
drilling of such wellbore(s). Such information is generally
obtained in the form of "well logs," such well logs being a record
with respect to position along the wellbore of various physical
parameters. Such parameters may include, for example, electrical
conductivity (resistivity), acoustic velocity, density, neutron
porosity and natural gamma radiation and formation fluid pressure
among others. Such well logs may be made during the drilling of the
wellbore, using so called "logging while drilling" (LWD)
measurements, or afterward, using well logging instruments conveyed
along the wellbore using armored electrical cable or other known
conveyance technique. A model may also be initially generated based
on well logs alone.
[0007] In order to adjust or update the initial model of the
Earth's subsurface structure in a useful manner based on such well
log data, it is necessary to know with reasonable precision the
geodetic position of the wellbore at every point along its length,
and the precise position along the wellbore of the particular well
logging instrument whose measurements are used to adjust the model.
The position along the wellbore is referred to as the "measured
depth" and may be reasonably precisely determined using techniques
well known in the art.
[0008] Determining the geodetic position of the wellbore at any
point along its length is typically performed using directional
sensors disposed in the well logging instrument. Such directional
sensors may include magnetometers to determine wellbore direction
with respect to the Earth's magnetic poles and accelerometers to
determine the inclination of the wellbore from vertical (gravity).
It is also known in the art to use inertial navigation devices to
determine geodetic direction of the wellbore. Irrespective of the
type of directional measurement instrument being used, limits on
their accuracy and precision result in some degree of uncertainty
as to the absolute geodetic position of the wellbore. There are
corresponding limits to the accuracy and precision of the initial
models made from seismic and/or electromagnetic surveys. As a
result, in some wellbore drilling operations, wherein it is
desirable to maintain the wellbore trajectory within a particular
formation within the Earth's subsurface, the degree of uncertainty
as to the relative positions of the wellbore and the subsurface
formations may limit the ability of the wellbore operator to so
maintain the wellbore trajectory.
[0009] More recently, apparatus and methods have been developed
that provide formation property measurements that are directionally
(azimuthally) sensitive, and can provide estimates of the distance
from the well logging instrument to one or more formation
boundaries (wherein a mineral composition and/or fluid content of
the formation changes). See, for example, U.S. Patent Application
Publication No. 2005/0140373 filed by Li et al. and assigned to the
assignee of the present invention.
[0010] There continues to be a need to more precisely determine the
position of a wellbore within structures in the Earth's subsurface
and to be able to navigate wellbores during drilling to maintain
such position along a desired trajectory with respect to subsurface
formations.
SUMMARY OF THE INVENTION
[0011] One aspect of the invention is a method for determining
structure in the Earth's subsurface. A method according to this
aspect of the invention includes generating an initial model of the
structure. The initial model includes at least one layer boundary.
A wellbore is drilled along a selected trajectory through the
Earth's subsurface in a volume represented by the initial model. At
least one formation parameter is measured azimuthally along the
wellbore. A distance from the wellbore is determined at selected
positions therealong to the at least one layer boundary using the
azimuthal parameter measurements. The initial model is adjusted
using the determined distances.
[0012] A system for modeling a subsurface structure of the Earth
according to another aspect of the invention includes an instrument
for measuring a formation parameter azimuthally along a wellbore
drilled through a volume of the Earth's subsurface represented by
an initial model. A processor is in signal communication with the
instrument. The processor is configured to determine a distance
from the wellbore to at least one formation boundary in the volume
from azimuthal measurements made by the instrument. The processor
is configured to adjust the initial model using the determined
distance.
[0013] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] FIG. 1 is an elevational view of a conventional rotary
drilling string in which the present invention may be used.
[0015] FIG. 2 is a schematic representation of a basic directional
measurement logging tool having symmetrical transmitter and
receiver antenna pairs.
[0016] FIG. 3A is a schematic representation of an example
directional measurement logging tool having a TRR configuration
that is insensitive to anisotropy at any dip angle.
[0017] FIG. 3B shows plots of the directional propagation response
for a three-layer formation using a logging tool according to FIG.
3A.
[0018] FIG. 4 shows a cross section of a well path superimposed on
an initial model and an updated model based on azimuthally
sensitive resistivity measurements.
[0019] FIG. 5 is a flow chart of one example of a method for
determining structure in the Earth's subsurface.
DETAILED DESCRIPTION
[0020] Methods and systems according to the various aspects of the
invention include making measurements along a wellbore of at least
one formation parameter using an instrument that is azimuthally
sensitive. The azimuthally sensitive formation parameter
measurements are made both along the wellbore and in a plurality of
azimuthal directions around the wellbore such that a distance can
be determined from the wellbore (or the instrument) to a formation
boundary. Two specific examples of azimuthal parameter measurements
that can be used to determine distance to a formation boundary
described in more detail below are resistivity of the formation and
acoustic travel time. As a matter of principle, the particular
formation parameter being measured only needs to have contrast at
formation layer boundaries, and be measurable at a sufficient
lateral distance from the wellbore to as to be able to effectively
determine the position of the wellbore with respect to such layer
boundaries without having the wellbore penetrate such boundaries.
Examples in this description that include a specific parameter,
such as resistivity, should not be considered limiting.
[0021] An apparatus and technique for measuring formation
resistivity as described in U.S. Patent Application Publication No.
2005/0140373 filed by Li et al. may be used in some examples of
implementing a method and system according to the present
invention. The apparatus and technique described in the '373
publication are in part described below with reference to FIGS.
1-3B in order to explain one example of how to determine position
of a wellbore with respect to subsurface formation boundaries. In
some examples, such determination may be used to more precisely
define the wellbore trajectory within the Earth's subsurface
structure than may be possible using directional measurements
alone. In some examples, such determination may be used to update
or refine a model of the structure of the Earth's subsurface.
[0022] FIG. 1 illustrates a conventional drilling rig and drill
string. A land-based platform and derrick assembly 10 are
positioned over a wellbore 11 penetrating a subsurface Earth
formation F. In the illustrated embodiment, the wellbore 11 is
formed by rotary drilling in a manner that is well known. It will
be readily appreciated by those skilled in the art, however, that
the present invention also finds application in directional
drilling applications as well as rotary drilling, and is not
limited to land-based rigs.
[0023] A drill string 12 is suspended within the wellbore 11 and
includes a drill bit 15 at its lower end. The drill string 12 is
rotated by a rotary table 16, energized by means not shown, which
engages a kelly 17 at the upper end of the drill string. The drill
string 12 is suspended from a hook 18, attached to a traveling
block (also not shown), through the kelly 17 and a rotary swivel 19
which permits rotation of the drill string relative to the hook.
Drilling fluid ("mud") 26 is stored in a tank or pit 27 formed at
the well site. A pump 29 moves the drilling fluid 26 to the
interior of the drill string 12 via a port in the swivel 19,
inducing the drilling fluid to flow downwardly through the drill
string 12 as indicated by arrow 9. The drilling fluid exits the
drill string 12 via ports in the drill bit 15, and then circulates
upwardly through the annular space between the outside of the drill
string and the wall of the wellbore, as indicated by arrows 32. In
this manner, the drilling fluid cools and lubricates the drill bit
15 and carries formation cuttings up to the surface as it is
returned to the pit 27 for recirculation. It will be appreciated by
those skilled in the art that the drill string 12 may alternatively
be rotated by a top drive (not shown) or similar rig-suspended
device. The lower portion of the drill string 12 may also be
rotated by an hydraulic motor (not shown) operated by flow of the
drilling fluid 26 and coupled within the drill string 12. Such
motors are known in the art as "mud motors." Accordingly, the
device used to rotate the drill string shown in FIG. 1 is not
intended to limit the scope of the invention.
[0024] The drill string 12 further includes a bottom hole assembly,
generally shown at 34, near the drill bit 15 (in other words,
within several drill collar lengths from the drill bit). The bottom
hole assembly 34 includes instruments for measuring, processing,
and storing measurement information, as well as communicating with
equipment at the Earth's surface. The bottom hole assembly 34 may
include, among other things, a measuring apparatus 36 for
determining and communicating the resistivity of the formation F
surrounding the wellbore 11. The measuring apparatus 36, also known
as a resistivity tool, includes a first pair of
transmitting/receiving antennas T, R, as well as a second pair of
transmitting/receiving antennas T', R'. The second pair of antennas
T', R' are symmetric with respect to the first pair of antennas T,
R, as is described in greater detail below. The measuring apparatus
36 further includes a controller to control the acquisition of
data, as is known in the art.
[0025] The bottom hole assembly ("BHA") 34 in the present example
can further include instruments housed within drill collars 38, 39
for performing various other measurement functions, such as
measurement of the natural gamma ray radiation, density (gamma ray
or neutron), neutron capture cross section, transverse and/or
longitudinal nuclear magnetic relaxation properties and fluid
pressure in the pore spaces of the formation F. Some devices for
measuring fluid pressure may make time indexed measurements such
that inferences of permeability of the formation F may be made. At
least some of the drill collars may include stabilizers 37, as is
well known in the art.
[0026] A surface/local communications subassembly 40 is also
included in the BHA 34, just above the drill collar 39. The
subassembly 40 includes a toroidal antenna 42 used for local
communication with the measuring apparatus 36 (although other known
local-communication means may be used), and a known type of
acoustic telemetry system that communicates with a similar system
(not shown) at the Earth's surface via signals induced in the
drilling fluid or mud by modulating the flow thereof. Thus, the
telemetry system in the subassembly 40 includes an acoustic
transmitter that generates an acoustic signal in the drilling fluid
("mud pulse") that is representative of measured downhole
parameters. The local communication subassembly 40 may also include
an electric and/or optical fiber telemetry device to transmit
signals at relatively high bandwidth over a so-called "wired" drill
pipe. Such pipe includes at least one insulated electrical
conductor and/or optical fiber along the entire length of the drill
string 12 such that signals may be transmitted to the Earth's
surface thereover. See, e.g., U.S. Pat. No. 7,017,667 issued to
Hall et al. and incorporated herein by reference.
[0027] The generated acoustical signal in the drilling fluid is
received at the surface by transducers represented by reference
numeral 31. The transducers 31, for example, piezoelectric
transducers, convert the received acoustical signals to electronic
signals. The output of the transducers 31 is coupled to an uphole
receiving subsystem 90, which demodulates the transmitted signals.
The output of the receiving subsystem 90 is then coupled to a
computer processor 85 and a recorder 45. The processor 85 may be
used to determine the formation resistivity profile (among other
things) on a "real time" basis while the wellbore is being drilled
or "tripped" (moving the drill string into and/or out of the
wellbore) or subsequently by accessing recorded data from a
recorder 45 associated with the subassembly 40. The computer
processor 85 may be coupled to a monitor 92 that employs a
graphical user interface ("GUI") through which the measured
downhole parameters and particular results derived therefrom (e.g.,
resistivity profiles) are graphically presented to a user.
Alternatively, if the signals are transmitted over electrical
and/or optical conductors, as described above, electrical and/or
optical coupling may be made to the receiving subsystem 90 for
decoding such signals.
[0028] An uphole transmitting system 95 is also provided for
receiving commands input by the user (e.g., using the GUI in the
monitor 92), and may be configured to selectively interrupt the
operation of the pump 29 in a manner that is detectable by
transducers 99 in the subassembly 40. In this manner, there is
two-way communication between the subassembly 40 and the uphole
equipment. A suitable subassembly 40 is described in greater detail
in U.S. Pat. Nos. 5,235,285 and 5,517,464, both of which are
assigned to the assignee of the present invention. Those skilled in
the art will appreciate that alternative acoustic techniques, as
well as other telemetry means (e.g., electromechanical,
electromagnetic), can be used for communication between the
subassembly 40 and the Earth's surface. As was explained above with
respect to electrical and/or optical telemetry, commands may also
be sent from the processor 85 to the local subassembly 40 in the
wellbore using such electrical and/or optical telemetry.
[0029] In the present example, two types of coil antennas can be
used to make resistivity measurements with directional (azimuthal)
sensitivity. One type provides directional sensitivity by having
the antenna either offset, e.g., from the center of a logging
instrument's longitudinal axis, or partially covered. Directional
measurements can also be made with an antenna configured so that
its magnetic moment is not aligned with the longitudinal axis of
the instrument. The present example may use the latter type of
directionally-sensitive antenna.
[0030] FIG. 2 schematically illustrates a basic resistivity tool 36
for directional electromagnetic (EM) wave measurement. The tool 36
includes a transmitter antenna T that induces an EM wave of a
selected frequency f and a receiver antenna R that is a selected
distance L away from the transmitter antenna T. Also shown is the
symmetric pair (T', R') described above with reference to FIG. 1
and which may be in accordance with the description in U.S. patent
application Publication No. 20003/0085707 fled by Minerbo et al.
and assigned to the assignee of the present invention. For clarity
and simplification, the description that follows will be limited to
the transmitter antenna T and the receiver antenna R, although it
is generally applicable to the symmetric antenna pair, T' and R'.
It should be noted that although the moment of the two symmetrical
antenna pairs are on the same plane in FIG. 2, this is not
required. As will be clear in the subsequent description, signals
from two pairs that have their moment in different planes can still
be added together to achieve equivalent results if the extracted
coefficients or directional phase-shift or attenuation are used in
a symmetrization operation.
[0031] In operation, the receiver antenna R will have a voltage
V.sub.RT induced therein by the EM wave from the transmitter
antenna T and its secondary currents produced in the formation
penetrated by the borehole containing the logging tool 36. Both
antennas T and R are fixed on the tool 36 and thus rotate with the
tool 36. The antenna orientations may be described as angles
.theta..sub.T for the transmitter antenna T, and .theta..sub.R for
the receiver antenna R. The azimuthal variation of the induced
voltage in the receiver R as the tool 36 rotates can then be
expressed in terms of the coupling of Cartesian components of the
magnetic dipoles.
[0032] One particular aspect of the measurements of phase-shift and
attenuation is that they are suited for "while drilling"
measurements, for which detailed characterization of thermal
electronics drift under downhole conditions is difficult to
perform. The directional phase-shift and attenuation measurements
defined herein have the benefit of a traditional
borehole-compensated propagation resistivity tool, namely that the
transmitter and receiver antenna characteristic and the drift of
the receiver electronics are all canceled out of the
measurement.
[0033] The above analyses can be extended straightforwardly to the
traditional TRR type of measurements, as described in the Minerbo
et al. publication referred to above. One skilled in the art can
easily show that this procedure produces essentially the same
response as indicated above, but with twice the signal when the
spacing between the receiver pair is much smaller comparing with
the TR spacing. The directional signals from the two receivers
simply add.
[0034] FIG. 3A shows a TRR configuration that is insensitive to
anisotropy (change in apparent resistivity of a formation with
respect to the direction of measurement) at any dip angle, and FIG.
3B shows responses according to this configuration. Transmitter
antenna T1 is energized and the phase shift and attenuation from
the receiver antennas R11, R12 is measured. Then, transmitter
antenna T2 is energized and the phase shift and attenuation from
the receiver antennas R21, R22 is measured. The tool reading
corresponds to the differences between these two sets of
measurements. Since the individual measurements are identical in a
homogeneous medium at any angle and with any anisotropy, the tool
readings are zero in a homogenous medium at any dip.
[0035] The measurement responses in a three-layer anisotropic
formation are shown in FIG. 3B. The tool reading is zero far from
the boundary at any dip, and there is little sensitivity to
anisotropy close to the boundary. Separation in responses results
from the fact that EM propagation responses are not completely
symmetric if the transmitter and receiver location are
interchanged. It should be observed that attenuation responses are
practically overlapping for different dip if all antennas are in
the same medium. The phase shift measurements are also overlapping,
although responses are double-valued in the conductive bed (1 S/m).
The manner in which distances to layer boundaries in the Earth's
subsurface from the azimuthally sensitive resistivity measurements
is well described in the '373 publication and need not be presented
herein in any more detail.
[0036] The above description is intended to provide an example of
how distances to boundaries of subsurface Earth formations from a
well logging instrument may be determined. Such determined
distances are used in some examples to adjust and/or update a model
of the structure of the Earth's subsurface.
[0037] FIG. 4 is an expanded scale view of a plane section of an in
initial model and an updated model to illustrate the principle of a
method according to the invention. An initial model of the Earth's
subsurface structure may be generated that includes the spatial
distribution (shown in 2 dimensions in FIG. 4) of various mineral
compositions of Earth formations, and of petrophysical properties
of such Earth formations, such as their fractional volume of pore
space (porosity), the fluid content in such pore spaces (water
saturation), fluid pressure in the pore spaces, and estimates of
permeability, among other properties. Alternatively, such models
may be of spatial distribution of petrophysical measurement
parameters, such as resistivity and natural gamma radiation. The
parameters used in the initial model are not intended to limit the
scope of the invention.
[0038] Such subsurface models may be initially generated using, for
example, seismic and/or electromagnetic survey information, as
explained above, among other techniques, where no subsurface
information is available. The initial model may from time to time
be updated or refined to reflect data obtained from one or more
wellbores drilled through the Earth's subsurface within the volume
represented by the initial model. Such updating, as is known in the
art, may include well log data such as resistivity, acoustic
velocity, neutron porosity, natural gamma radiation, density and
fluid pressures, among other data. The data used to refine or
update the model may also include actual samples of the subsurface
Earth formations (cores). So-called "checkshot" surveys may also be
obtained from within such wellbores in order to measure seismic
travel time from the surface to selected depths in the wellbore, so
that the seismic survey data may be corrected for the effects of
varying formation seismic velocity through the subsurface. If no
seismic data or electromagnetic survey data are available, the
initial model may be made entirely from subsurface information. It
is also known in the art to construct initial models entirely from
well log data and formation sample (core) data. Accordingly, the
source of data used to generate the initial model is not a limit on
the scope of the invention.
[0039] Because well log data are typically recorded with respect to
what is inferred to be the depth in the Earth, such well log data
may preferably be obtained from wellbores drilled such that any
uncertainty in the actual geodetic position of the wellbore within
the Earth's subsurface, resulting from limitations of accuracy and
precision of wellbore directional measuring instruments, will have
relatively little effect on the model. Such wellbores are those in
which the wellbore intersects the various subsurface formations
relatively close to perpendicularly to the attitude of the
formation. In formations that are relatively horizontally disposed,
therefore, such wells would be substantially vertical. It is to be
clearly understood that the invention is not limited in scope to
using well log data obtained from wellbores drilled perpendicularly
through the subsurface formations. As a practical matter, however,
the invention may have particular application in the placement of
wellbores drilled substantially parallel to the attitude of one or
more subsurface formations, or in using data obtained from such
wellbores to update models of the Earth's subsurface over a wide
geodetic area. As will be appreciated by those skilled in the art,
to a large extent, subsurface formations of interest to producers
of oil and gas are largely modeled as substantially horizontally
disposed layers of rock, wherein wellbores drilled parallel to the
layering thereof are substantially horizontally disposed.
[0040] An important aspect of such subsurface models, whether
updated by well log data or not, is an expected spatial
distribution of one or more formations that are intended to be
penetrated by a wellbore in a direction essentially parallel to
their attitudes. Those skilled in the art will appreciate that one
example of such spatial distribution is a subsurface hydrocarbon
reservoir formation. Such reservoir may have an oil/water contact
therein. An objective of drilling a wellbore through such
reservoirs may be to maintain the well path to the greatest extent
possible within an oil layer disposed above the oil/water contact.
In FIG. 4, an initial model (which may be updated by well log data
as explained above) may include a spatial distribution of a
reservoir upper limit 54A. Such upper limit may represent the
boundary between the reservoir bearing formation and an overlying
"cap rock" (not shown) consisting of relatively impermeable
formation(s). Spatial distribution of a lower limit of the
reservoir from the initial model is shown at 54C. A fluid contact
is shown at 54B. Such fluid contact 54B may be an oil/water
contact, a gas/oil contact, or a gas/water contact, for example. A
wellbore trajectory through the subsurface formations projected
onto the initial model is shown in FIG. 4 at 52.
[0041] During or after drilling of the wellbore, azimuthal
resistivity measurements may be made as explained above with
reference to FIGS. 1-3B, and at selected positions along the
wellbore, a distance to an upper formation boundary, shown at
d.sub.1, and a distance to a lower formation boundary, shown at
d.sub.2, may be determined as explained above using such azimuthal
resistivity measurements. Using the determined distances, d.sub.1,
d.sub.2, an updated or adjusted position of the upper limit and
lower limit may be determined, as shown generally at 50A for the
upper limit and at 50B for the lower limit. The updated positions
of the upper 50A and lower 50B limits may then be used to update
the initial model of the Earth's subsurface.
[0042] An example method according to the invention will now be
explained with reference to the flow chart in FIG. 5. At 60, an
initial model of the Earth's subsurface is generated. Such initial
model, as explained above, may be made using seismic and/or
electromagnetic surveying, and may be updated or refined using well
log data and/or formation sample data if such data are available.
At 62, in a wellbore drilled at high incident angle to the attitude
of formations of interest, azimuthally sensitive measurements of a
formations parameter such as resistivity, are made. Such
measurements may be made during drilling the wellbore or
thereafter. At 64, using such measurements, at various positions
along the wellbore, a distance may be determined from the wellbore
to one or more formation boundaries. Such boundaries may include
fluid contacts and/or formation composition changes, as explained
above.
[0043] The distances determined at 64 may be used, at 66, to update
or refine the initial model. The initial model may be adjusted to
reflect the above determined distances from the wellbore.
[0044] At 68, other well log measurements may be made, either
contemporaneously with the azimuthally sensitive resistivity
measurements or afterward. Because the position of the wellbore
with respect to the formation boundaries will be better determined
as a result of performing the distance determination at 64, such
other well log measurements will more precisely associated, as
shown at 70, with particular subsurface formations estimated from
the initial model. At 72, the updated model determined at 66 may be
refined using the additional or subsequent well log data. The
initial model, updated or adjusted models and any other well log or
other data may be stored in the processor (85 in FIG. 1) and/or
displayed using the GUI monitor (92 in FIG. 1).
[0045] In some examples, the determined geodetic position of the
wellbore along its trajectory may be refined, at 74, and the
refined position information may be used in conjunction with the
boundary distance determination at 64 to update the model of the
Earth's subsurface. As explained above, the wellbore trajectory
(position at each point along its length) may be determined during
drilling using directional sensors disposed in one or more of the
components of the drill string. During drilling or afterward, the
measurements made by the directional sensors may be supplemented by
such data as checkshot survey determined seismic travel time.
Checkshot surveys may be performed during drilling or afterward.
See, for example, U.S. Pat. No. 5,555,220 issued to Minto and U.S.
Patent Application Publication No. 2005/0041526 filed by Esmersoy
et al. and assigned to the assignee of the present invention. A
checkshot survey may enable more precise determination of the
position of the wellbore with respect to a seismic section. By more
precise determination of the wellbore position with respect to the
seismic section, and by using the determined distances to the layer
boundaries, it may be possible to refine the model with respect to
the seismic section. If the seismic section suggests, for example,
that there is relatively little lateral velocity variation in the
Earth's subsurface within the model volume, then a seismic time to
depth record made in a near-vertical wellbore within the model
volume may be used to calibrate the checkshot survey with respect
to depth. Thus, the model may be refined to more precisely position
the layer boundaries with respect to depth in the subsurface.
[0046] As previously stated, other formation parameters may be
measured azimuthally to determine the distance from the wellbore to
the formation boundary. U.S. Pat. No. 7,035,165 issued to Tang,
incorporated herein by reference, describes using acoustic
measurements to make such distance determinations. As described in
the Tang '165 patent, such measurements and determinations may be
made as follows. A plurality of multicomponent acoustic
measurements indicative of a formation parameter of interest
(typically acoustic velocity or slowness) is obtained at a
plurality of wellbore positions (depths) and for a plurality of
source-receiver spacings on the logging instrument. An orientation
sensor on the instrument, which can be a magnetometer, is used for
obtaining an orientation measurement indicative of an orientation
of the logging instrument. The multicomponent acoustic measurements
are mathematically transformed (rotated) to a fixed coordinate
system such as a geodetic system defined with respect to magnetic
or geographic north, using the orientation measurement, giving
rotated multicomponent measurements. The rotated multicomponent
measurements are processed for obtaining the parameter of interest.
In one example, the parameter of interest includes an azimuth and
relative dip of the bed boundary. In one example, the
multicomponent measurements are made with a cross-dipole acoustic
sensor. In another example, the multicomponent measurements are
hybrid data, i.e., obtained from either a monopole source into a
cross-dipole receiver pair or a cross-dipole source into a monopole
receiver.
[0047] When measurements are made at a plurality of depths, the
processing can provide a migrated image of bed boundaries in the
earth formation. In one example, compressional waves produced by a
dipole source are used. Prior to migration, certain pre-processing
may be used, such as high pass filtering, first break
determination, frequency-wavenumber (f-k) filtering, dip median
filtering, and, selective gating of the data in time windows. On
the migrated sections, the relative dip may be obtained by fitting
a line to a linear trend on one of said plurality of migrated image
data sections. The azimuth is determined by an inversion of the
migrated image data sections, the inversion based at least in part
on minimizing a cost function over an image area of interest.
[0048] A system for modeling subsurface Earth structures may
include formation parameter measuring and data processing
components such as shown in and explained above with reference to
FIG. 1. Such a system includes an instrument for azimuthally
measuring at least one formation parameter. One example of a
parameter may be resistivity, as explained above. Another example
of a parameter may be acoustic velocity, also as explained above.
The system may include a processor for storing an initial model of
the subsurface Earth structure. The processor may be configured to
process the azimuthal parameter measurements to determine distance
to a formation boundary at selected positions along a wellbore. The
processor may be configured to adjust the initial model using the
distance measurements. The processor may be configured to adjust
the model using at least one additional petrophysical parameter
measured in the wellbore. The processor may be operatively coupled
to a display for producing a visible image of the initial and/or
adjusted model. In one example, the system includes a so-called
"wired" drill string having therein an electrical conductor and/or
optical fiber that enables measurements from the azimuthal
measuring instrument to be communicated to the processor
substantially in real time, such that the model may be adjusted
substantially in real time.
[0049] Methods and systems according to the invention may result in
more precise models of spatial distribution of subsurface
formations and their fluid content. More precise models may improve
the drilling of subsequent wellbores to optimize drainage of
subsurface reservoirs, by reducing placement of wellbores into
unsuitable formations.
[0050] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
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