FIELD OF THE INVENTION
The present disclosure relates generally to making measurements
related to oil and gas exploration. More particularly, embodiments of the
5 disclosure relate to systems and methods for measuring electromagnetic fields
to detect a number of nearby wellbores, and to determine the locations of the
nearby well bores.
BACKGROUND
In drilling wells for oil and gas exploration, understanding the structure
10 and properties of the associated geological formation provides information to
aid such exploration. In addition, drilling can be enhanced with systems and
methods to detect conductive bodies below the earth's surface. The conductive
bodies can include metal structures, e.g., casing and piping used in various
down-hole operations, where the detection of the metal structures can reveal
15 subtetTanean positions of existing wellbores. For example, the positions of
existing wellbores can influence drilling operations in crowded fields where
legal or land restrictions require wells to be drilled in close proximity with one
another. In some instances, well avoidance is an important consideration in
drilling in the crowded fields, and in some instances, well intersection can be
20 intentional, e.g., for the repair of a damaged well bore.
In other instances, determining the position of existing well bores can
facilitate drilling a wellbore in a predetermined relationship to the existing
wellbore. For example, in steam assisted gravity drainage (SAGD)
applications, a wellbore is often drilled parallel to existing wellbores.
25 Generally in SAGD applications, steam is used in conjunction with two spaced
apati well bores( an SAGD pair) to address the mobility problem of heavy oil in
a fonnation. High temperature steam may be injected into an upper wellbore
(the injector), and used to heat the heavy oil to reduce its viscosity and thereby
enhance the flow of the heavy oil into a lower wellbore (the producer)to
30 enhance extraction of the heavy oil. Preferably, the injector and producer are
drilled at a distance of only a few meters from one other, e.g., about 5 to about
- 2 -
15 meters. If the injector is positioned too close to the producer, the producer
would be exposed to very high pressure and temperature and steam would be
directly communicated to the producer. If the injector is positioned too far
fl·om the producer, the efficiency of the SAGD process is reduced. In order to
5 assist in ensuring that the injector of an SAGD pair is positioned as desired
relative to the producer well bore, a survey of the geologic formation is often
conducted. These surveying techniques are traditionally referred to as
"ranging." Often, these ranging techniques can be frustrated by the proximity
of multiple nearby well bores, e.g., where it can be difficult to distinguish
10 magnetic fields contributed from a target wellbore from other nearby existing
well bores in a crowded tield.
BRIEF DESCRIPTION OF THE DRAWINGS
The disclosure is described in detail hereinafter on the basis of
embodiments represented in the accompanying figures, in which:
15 FIG. lA is a cross-sectional schematic side-view of a system of
wcllbores including first and second existing wellbores and a third wellbore
having a drill string or other conveyance equipped with a ranging tool
disposed therein in accordance with one or more exemplary embodiments of
the disclosure;
20 FIG. lB is a cross-sectional schematic top-view of the system of
well bores of FIG. I A illustrating a crowded field of existing well bores
proximate the first, second and third well bores;
FIG. 2 is a schematic diagram of system for determining the number
and locations of multiple well bores including receivers of the ranging tool of
25 FIG. lAin accordance with example embodiments of the disclosure;
FIG. 3 is a schematic view of the ranging tool and the first well bore of
FIG. !A illustrating various parameters of the first wellbore that are
determinable by the system of FIG. 2;
FIG. 4 is a schematic view of the ranging tool and multiple well bores
30 of the network of FIG. I A illustrating magnetic fields detectable by the
ranging tool;
- 3 -
FIGS. SA and SBare flowcharts illustrating operational procedures that
include locating multiple wellbores in accordance with example embodiments
of the disclosure;
FIG. 6 is a graphical view of a mathematically simulated example of a
5 two-wellbore system illustrating simulated location curves for first and second
well bores and a simulated path of a ranging tool for detennining the respective
locations of the first and second well bores using an inversion portion of the
operational procedure illustrated in FIG. SA;
FIG. 7 is a schematic view of a sensor anangement for the ranging tool
10 of FIG. 6;
FIG. 8 is a graphical view of the simulated two-wellbore system of
FIG. 6 illustrating positional data points calculated for the first and second
well bores overlying the respective simulated location curves; and
FIGS. 9A and 9B are graphical views illustrating data indicative of a
15 current magnitude calculated for a simulated cUtTent of 1 Amp flowing
respectively through the first and second wellbores of FIG. 6.
DESCRIPTION OF INVENTION w.r.t. DRAWINGS
In the interest of clarity, not all features of an actual implementation or
method are described in this specification. Also, the "exemplary"
20 embodiments described herein refer to examples of the present invention. In
the development of any such actual embodiment, numerous
implementation-specific decisions may be made to achieve specific goals,
which may vary from one implementation to another. Such would
nevertheless be a routine undertaking for those of ordinary skill in the art
25 having the benefit of this disclosure. Further aspects and advantages of the
various embodiments and related methods of the invention will become
apparent from consideration of the following description and drawings.
The present disclosure may repeat reference numerals and/or letters in
the various examples. This repetition is for the purpose of simplicity and
30 clarity and does not in itself dictate a relationship between the various
embodiments and/or configurations discussed. Further, spatially relative
- 4-
tenns, such as "below," "upper," "up-hole," "down-hole," and the like, may
be used herein for ease of description to describe one element or feature's
relationship to another element(s) or feature(s) as illustrated in the figures.
The spatially relative terms are intended to encompass different orientations of
5 the apparatus in use or operation in addition to the orientation depicted in the
figures.
Figure I illustrates a multi-wellbore system 10 including a first
wellbore 12 and a second wellbore 14 formed in a geologic formation "G." In
some exemplary embodiments, the geologic formation "G" is an oil sand or
10 other heavy oil formation disposed at a relatively shallow depth, e.g., 70-600
m below a surface location "S." The first and second wellbores 12, 14 can be
employed for recovery of heavy oil from the geologic formation "G" using
processes such as SAGO operations. The systems and methods, in accordance
with the teaching herein, can be used to provide SAGO steering, and such
15 SAGO steering can be applied to non-horizontal wells as well. Although the
multi-wellbore system I 0 is described herein below as employed in
conjunction with SAGO operations, it should be appreciated that aspects of
disclosure may be practiced in conjunction with offshore ranging operations or
other types of exploration as well.
20 The first and second wellbores 12, 14 include respective electrically
conductive bodies 12a, 14a therein. The electrically conductive bodies 12a,
14a can include strings of casing pipe, production tubing or other elongate
metallic media in which electrical currents can be excited. As described in
greater detail below, electrical cutTents excited in the electrically conductive
25 bodies 12a, 14a in the first and second wellbores 12, 14 can facilitate magnetic
ranging processes for drilling a third wellbore 16 along a path having a
predetermined relationship with a path defined by the first wellbore 12. The
predetermined relationship can include, e.g., a generally parallel, horizontal
relationship to facilitate SAGO operations. By allowing two or more
30 wellbores 12, 16 to be positioned within extremely tight tolerances, magnetic
ranging technology can help eliminate positional uncertainty of conventional
surveys and can provide more precise tolerance for SAGO wells. In other
- 5-
embodiments, the predete1mined relationship can be an intersecting
relationship where the third wellbore 16 intersects the first wellbore 12 at a
predetermined and/or true depth, a lateral branching relationship where the
third wcllbore 16 branches from the first wellbore 12at a predetermined
5 location.
The first wellbore 12 can be employed as the "producer" in a SAGD
system and the third well bore 16 can be employed as the "injector" in a SAGD
system. The third well bore 16 is being drilled proximate the first wellbore 12
at a distance "D" theretl·om. In some example embodiments, the distance "D"
10 can be in the range of about 5 to about 15 meters. The third wellbore 16 is
being drilled with a drill string 18 having a drill bit 20 at a lower end thereof.
A slant drilling rig 22 is erected at the surface location "S" to support the drill
string 18 at shallow angles, e.g., at angles in the range of about !5° to about
75° from horizontal. In some example embodiments, the slant drilling rig 22
15 can support the drill string 18 at angles of between 0° and 90° (inclusive) from
horizontal. Often slant drilling is employed to facilitate access to the shallow
geologic fmmations "G" where heavy oils are entrapped and SAGD
operations are generally conducted.
A ranging tool 26 is calTied by the drill string 18. The ranging tool 26
20 can be employed to determine the location of the conductive body 12a within
the first wellbore 12, thus permitting the drill bit 20 to be steered to maintain
the third wellbore 16 at the distance "D" from the first wellbore 12, or at any
spatial relationship therewith. As described in greater detail below, the
ranging tool 26 is operable to detect a magnetic field generated by separate
25 electric cu!Tents propagated through electrically conductive bodies 12a, 14a,
and measure wellbore parameters of both the first and second wellbores 12, 14
to guide the drill string 18. In some example embodiments, the ranging tool
26 can be deployed independently of a drill string 18. For example, the
ranging tool 26 can be deployed into an additional existing wellbore (not
30 shown) by wireline, coiled tubing or other recognized methods. Alternatively
or additionally, the ranging tool 26 can be deployed by moving the ranging
tool 26 across the surface location "S."
- 6-
The electric currents propagated through the conductive bodies 12a,
14a can be excited in any recognized manner, e.g., by using a down-hole
electrode source 30, or by directly coupling an electrically conductive body
12a to a current source 32 at the surface location "S." In some example
5 embodiments, the currents can be remotely excited by coil antennas 34, which
form a pmi of, or are carried by, the drill string 18. In some embodiments, the
electrical currents can be excited by the transmitters 52 (FIG. 2) provided in
the ranging tool 26.
Referring to FIG. 1 B, in some example embodiments, the first well bore
10 12 in the multi-wellbore system 10 can have a plurality of"fishbone" or lateral
wellbores 12' branching therefrom. The lateral wellbores 12' can permit
production from a wider expanse of the geologic formation "G" than through
the first wellbore 12 alone. Similarly, the second wellbore 14 can include
lateral well bore 14' branching therefrom. Additional well bores 36a through
15 36c are drilled in the vicinity of the first and second wellbores 12, 14 and
together with the respective lateral well bores 36a' through 36c', the wellbores
12, 14 and 36a through 36c can produce from a relatively large horizontal area
of the geologic formation "G." Each of the well bores 12, 14and 36a through
36c can be drilled from a relatively small, common drilling area 40. The field
20 of wellbores defined by the wellbores 12, 14 and 36a through 36c can be
characterized as a crowded field, particularly near the common drilling area
40.As the third well bore 16 is drilled through the crowded field, e.g., from the
drilling area (point A) to a te~minal end (point B), the number of "nearby"
well bores t!·equently changes. As used herein, a "nearby wellbore" includes at
25 least a well bore having a current excited therein that produces a magnetic field
detectable by a ranging tool 26. Each one of the well bores 36a through 36c,
and each of the respective lateral wellbores 36a' through 36c' can also include
an individual electrically conductive body (not explicitly shown) therein that
can generate a magnetic field detectable by the ranging tool 26. Thus,
30 accurately interpreting the electromagnetic field received and detected by the
ranging tool 26 at any particular location can include detetmining a number of
well bores making a contribution to the received electromagnetic field.
- 7-
Refening to FIG. 2 and with continued reference to FIGS. !A and IB,
a system 50 for determining the number, locations and/or other wellbore
parameters of multiple wellbores is illustrated. The system 50 can include
transmitters 52 and receivers 54. In some example embodiments, the
5 transmitters 52 can form a part of the ranging tool 26, and can be carried by a
drill string 18 (FIG. 1 A). The transmitters 52 can be operable to generate an
electromagnetic probe signal that causes current to flow in the electrically
conductive bodies 12a, 14a (FIG. !A). In some example embodiments, the
transmitters 52 can include a focused electric dipole source operable to induce
10 the electric current in the electrically conductive body 16, which is exterior to
the structure of the transmitters 52. In some example embodiments, the
transmitters 52 can be deployed independently of the ranging tool 26, e.g., by
wireline into an adjacent wellbore 36b, or can be mounted at stationary
location with respect to the geologic formation "G." As used herein, the term
15 "transmitter" car1 include other such mechanisms for inducing the electric
currents in the electrically conductive bodies 12a and 14c (FIG. !A) such as
the electrode 30 and/or cunent source 32.
The receivers 54 may include any mechanism that detects, measures
and/or collects a magnetic field for processing. For example, coil antennas or
20 magnetometers can be used. The receivers 54 ca11 be operable to measure or
collect for processing an electromagnetic field emitted from one or more
electrically conductive bodies 16 (FIG. 1 A), as a result of the probe signal
generated from the transmitters 52. The electrically conductive bodies 12a,
14a, and the wellbores 12, 14, 36a through 36c and 36a' through 36c'
25 containing the electrically conductive bodies 12a, 14a, can be detected from
the magnetic field, and the appropriate locations and other wellbore
parameters can be determined therefrom.
The system 50 also includes a communications unit 56, which
facilitates interaction among a system control center 58, a visualizing unit 60
30 and the transmitters 52 and receivers 54. The communications unit 56 can
provide a bi-directional telemetry system for communication between downhole
components, e.g., the ranging tool 26, and components located at the
- 8-
surface location "S," e.g., the visualizing unit 60. Communications unit 56
can employ combinations of wired communication technologies and wireless
teclmologies at frequencies that do not interfere with on-going measurements
made by the ranging tool 56. The visualizing unit 60 can include computer
5 monitors, printers or other devices that pennit an operator at the surface
location "S" to monitor data generated by the system 50. The operator may
monitor the data to determine whether intervention into the system 50 is
necessary.
The system control center 58 can be disposed within the ranging tool
10 26, at another down-hole location, or at the surface location "S," and can
include a computer with a processor and a non-transitory memory associated
therewith. The system control center 58 can manage the generation of
transmission signals, e.g., instmctions signals for the transmitters 52, and can
manage the collection of received signals, e.g., data signals from the receivers
15 54, cmTesponding to the transmission signals. The frequency at which the
transmission signals are provided can be controlled by the system control
center 58. The system control center 58 is also operably coupled to a data
acquisition unit 62 and a data processing unit 64. The data acquisition unit 62
can include analog to digital conve1iers, or other mechanisms for converting
20 the received signals into a form useable by the system control center 58 and/or
the data processing unit 64.
The data processing unit 64 can convert the received signals into
information indicating the number, position and directional characteristics of
well bores in the vicinity of the ranging tool 26 as described in greater detail
25 below. This infonnation can be provided to the visualizing unit 60 for
evaluation by an operator. In some embodiments, the data processing unit 64
may include a processor 64a and a computer readable medium 64b operably
coupled thereto. The computer readable medium 64b can include a
nonvolatile or non-transitmy memory with data and instructions that are
30 accessible to the processor 64a and executable thereby. In one or more
embodiments, the computer readable medium 64b is pre-programmed with
predetennined thresholds Thfield and Thmisfit, which, as described in greater
- 9-
detail below, can be at least pmiially dependent on characteristics of the
ranging tool 26. The computer readable medium 64b may also be preprogrmnmed
with predetetmined sequences of instructions for performing
various steps of procedures I 00, 200 described below with reference to FIGS.
5 SA and 5B.
Referring to l'IG. 3, parameters associated with a wellbore, which can
be determined by the data processing unit 64 (FIG. 2) are illustrated. These
parameters include position and direction parameters that can fully define the
location of the wellbore in three-dimensional space. Only the first well bore 12
10 is illustrated in FIG. 3, although, each wellbore in the multi-wellbore system
I 0 can be defined by a similar parameter set.
In one or more embodiments, a wellbore parameter set may include a
vector parameter l;, which represents a current flowing through the wellbore
12 in an axial direction of the wellbore 12, and a vector parameter ri
15 representing an mihogonal distance between the wellbore 12 and a reference
point "P" defined with respect to the ranging tool 26. The reference point "P"
is illustrated at the center of coordinate system 66, and the vector parameters
l;and ri can be directionally defined with respect to the coordinate system 66.
The subscript "i" denotes an index number of the first well bore 12, or more
20 generally, any of the well bores in a multi-wellbore system 10. The index "i"
is an integer ranging from I to N'ipe, where N"ipe is a number of wellbores.
The number of wellbores represented by N"ipe can be a total number of
well bores in a multi-wellbore system I 0, a number of nearby well bores that
make a non-negligible contribution (defined in greater detail below) to the
25 magnetic field detected by the ranging tool 26, or an estimated number of
4 4 wells. Both of the vector parameters /iand rihave three degrees of freedom,
and thus, there are at least six variables or "unknown" parameters in a
parameter set associated with the first well bore 12,and each of the N"ipe wells.
4 4 The vector parameters /iand riare determinable by the system 50, and other
30 parameters such as azimuth angle and orientation of the first well bore 12 can
4 4 be determined from the vector parameters /iand ri. For steering the ranging
- 10-
tool 26 relative to the first wellbore 12, it is not necessarily required to
determine the strength of the current propagated tlu·ough the first wellbore 12,
i.e., the magnitude of current vector I;. However, as described below,
determining the current vector I;can facilitate determining the contribution of
5 the first well bore 12 to a field detected by the ranging tool 26.
As illustrated in FIG. 4, a first magnetic field H1 is induced by the first
effective current lerr1 flowing through the first well bore 12. A second magnetic
field H2 is induced by a second effective current !err, flowing tlu·ough the
second well bore 14. The ranging tool 26 is located at within the third well bore
10 16 at respective radial distances R1 and R2 from the wellbores 12 and 14. The
ranging tool 26 can include receivers 54 in the form of tri-axial coil antennas,
i.e., a set of three antennas whose magnetic moment vectors form an
orthogonal system spanning the entire field. Thus, the ranging tool 26 can be
sensitive to the fields H1 and H2, regardless of the orientation of the fields Ht
15 and H2 with respect to the receivers 54. The combined magnetic field detected
by the ranging tool 26 includes a contribution from each of the fields Ht and
H2. Assuming that the wellbores 12 and 14 are infinitely long, and assuming
that the effective currents lerr1 and Ierr2 are constant, each of the magnetic
fields H1 and H2 can be expressed by equation (I) below.
20
(1)
In equation (I), H denotes the magnetic field,$ is the unit vector in an
azimuthal direction, and ris the position vector for the receivers 54 (FIG. 2) of
the ranging tool 26. Even though equation (I) is used as the basis of the
mathematical formulation presented next, in some exemplary embodiments, is
possible to replace equation (I) with a more precise version of the equation by
25 including the axial variations of the cmTent on a pipe, for example. From
~ equation (I) it is seen that the magnetic field H detected by the ranging tool 26
can be inversely propottional to the radial distances R1 and R2 between the
wellbores 12 and 14and the receivers 54. The assumptions regarding the
infinite lengths and constant currents have generally been demonstrated to
- 11-
yield suftlciently accurate approximations of the wellbore parameters for
steering purposes. In particular, these assumptions yield relatively accurate
approximations of the well bore parameters for well bores nearest the receivers
54 where the radial distances R1 and R2 are the smallest and where accuracy
5 can be relatively significant for steering. The formulation of the magnetic
fields given in equation (I) is thus employed throughout this specification.
However, if different descriptions of the magnetic fields radiated from the
well bores are available; these descriptions may be employed without departing
from the spirit and scope of the present disclosure.
10 When the ranging tool 26 is deployed, each receJVer 54 can make
distinct measurements of the total magnetic fieldH. A number of receivers 54
provided on the ranging tool 26 can be designated as N·ec. In some exemplary
embodiments, at least some of the receivers 54 are single axis magnetometers,
and in some exemplary embodiments, at least some of the receivers 54 are tri-
15 axial or other multi-axial receivers. The number of receivers N'"c can
designate the number of axes along which the receivers are disposed. For
example, where four (4) tri-axial receivers 54 are provided on a ranging tool
26 in various orientations, the number of receivers N·ec can be defined as
twelve (12). Using the formulation for the magnetic fields given in equation
20 (I) above, for each of the N·ec receivers 54, the magnetic field can be described
by one of theN'' cequations illustrated by equations (2) through (3) below.
In equations (2) through (3), Huk generally denotes the magnetic field
measured by the k'" receiver 54 of the ranging tool 26, where k is an index
number ranging from I to N·ec. The variable ilk represents the unit vector in
- 12-
the direction that the /(11 receiver 54 is oriented to receive the magnetic field,
e.g., the magnetic moment vector's direction for a magnetic dipole. The
variable ru~cis the position vector of the !(" receiver 54 with respect to the
reference point "P." These equations indicate that the magnetic field Huk
5 detected by one of the receivers 54 will be a summation of the contributions
made by each of the N"ipe cunents induced in well bores.
In addition to the N·ec equations (2) through (3), another system of
equations can be defined for the wellbore parameters using the assumption that
the direction of the cunent induced in a well bore will be orthogonal to the
10 position vector. As illustrated in the N"ipe equations in equations ( 4) through
(5) below, the inner dot product of the two mthogonal vectors ~ and r; will be
zero.
(4)
(5)
The total number of equations defined by equations 2 through 5 is
(N'""e + N''"') the sum of the number of well bores (N''ipe) and the number of
15 receivers (N''"'). Since there are six "unknown" parameters associated with
each of the N"ipe wellbores as described above, the total number of unknown
parameters, and thus the minimum number of equations necessary for
obtaining an unambiguous solution for the unknown parameters is 6 X
Npipe .Thus, to obtain an unambiguous solution for the unknown wellbore
20 parameters, the relation indicated in relation (6) below should generally be
met. It follows that generally, the number of well bores N"ipe can be a function
of the number of receivers Nrec provided, and a maximum number of well bores
that can be determined unambiguously as illustrated in relation (7).
(6)
. Nrec
=; Nptpe < __ = Nmax
- 5 (7)
-13-
In some instances, where some additional information is available or
can be estimated, a fewer number of receivers Nrec can allow for a greater
number of well bores N"ipe to be located. For example, where it is known, or it
can be estimated, that each of the wellbores in a multi-wellbore system is
5 parallel, the general relations (6) and (7) can be reduced to relations (8) and (9)
below.
Npipe + Nrec ;:: 4 X Npipe + 2 (8)
(Nrec _ 2)
=> Npipe < = Nmax
- 3
(9)
~ This reduction is possible where the direction of each of the currents I;
is known to be the same for each wellbore although the amplitude for each
current l; may be dissimilar. In some embodiments, this infmmation can be
10 known, e.g., in a multi-wellbore system including a one or more parallel of
SAGD pairs.
The number of well bores N"ipe can include a number of well bores that
produce a non-negligible magnetic field at the ranging tool 26. In a crowded
field, such as the field depicted in FIG. JB, contributions from a large number
15 of wellbores may be detected by the ranging tool 26. However, some of these
contributions may be negligible. For example, the attenuation of the magnetic
fields produced by currents induced in wellbores at large distances from the
ranging tool 26 can produce relatively small contributions to the magnetic
fields detected. Also, destmctive interference can produce a cancellation
20 effect on the magnetic fields than can contribute to relatively small
contributions to the magnetic fields detected. The definition of negligibility
can be dependent on several system-dependent characteristics or requirements
such as accuracy, noise floor, etc. A threshold Thfield can be predetermined by
one skilled in the art below which a particular contribution can be considered
25 negligible and removed from further consideration as part of the multiwellbore
system.
Refe11'ing to FIG. SA, and with continued reference to FIG. 2, an
operational procedure I 00 can be employed for locating multiple well bores
- 14-
using the data processing unit 64 of system 50 (FIG. 2). Preconditions for the
procedure I 00 can include that a current is induced in each well bore to be
located, the ranging tool 26 is deployed at a first operational location, and a
received magnetic fieldHr'cfrom the first operational location is detected by
5 the receivers 54 and communicated to the data processing unit 64, which
accepts the received magnetic field ifrec as input. The operational procedure
I 00 begins at step I 02 where the received magnetic field jfrec is received by
the data processing unit and evaluated to determine if the magnitude or norm
of the received magnetic field ifrec is greater than the predetermined field
10 threshold Thfield for negligibility. If the norm of the received magnetic field
ifrec is not greater than the predetermined field threshold Thfield, then it can be
determined that there are no nearby wellbores producing a non-negligible
magnetic field. The procedure I 00 proceeds to step 104 where the procedure
100 may end. Optionally, at the end of the procedure 100, the data processing
15 unit 64 can provide a status to the visualization unit 60, such that a user can be
alerted that no nearby wcllbores were located at the first operational position.
The ranging tool 26 can then be moved to a second operational position, and
the procedure 1 00 can be repeated. The preconditions and post process return
to step 102 where another received magnetic field ifreccan be evaluated.
20 Where it is determined at step I 02 that the norm of the received
magnetic field jfrec is greater than the predetermined field threshold Thfield,
there may be nearby well bores contributing to the received magnetic field ifrec.
The procedure 100 proceeds to step I 06 where an iterative inversion process
can be initiated to determine the number and locations of the contributing
25 well bores. Initially, at step I 06, an estimated number of contributing
well bores can be selected. Generally, an estimate of one (1) can be selected,
although in some exemplary embodiments a higher number of wellbores can
be estimated, e.g., if it is known that a minimum number of wellbores arc
nearby. The variable N'ipe is set to the initial estimate at step I 06.
30 Next, the procedure I 00 proceeds to step I 08 where at least one
parameter set is calculated for the estimated number of well bores Npipe which
- 15-
would produce the received magnetic field Jirec. For example, when the
estimated number of well bores N"ipe is set to one (I), the parameter set for a
single wellbore which would produce the received magnetic field Jirec at the
operational location of the receivers is calculated. The at least one parameter
5 set may include the at least the six unknown parameters associated with the
~ ~ vector parameters /iand r;, and can be calculated by solving the system of
equations defined by equations (2) through (5) described above. Often, this
system of equations will not have a unique solution, and solving the system of
equations yields a plurality of parameter sets. A forward model magnetic field
10 Jifor is determined for each parameter set. The fmward model magnetic
fieldsJifor can be determined by solving equation (2) above. Next, for each
forward model Jifor determined, the nann of the difference between the
received magnetic field Jirec and the forward model magnetic fieldJifor, and the
parameter set producing the minimum value is selected. For example, the
15 parameter set that satisfies min{IIJirec- Jitarll} for the estimated number of
well bores Npipe is selected.
Next, the procedure 100 proceeds to step 110, where the norm of the
difference between the received magnetic field Jirecand forward model
magneticJlfm'for the selected parameter set, i.e., min{IIJirec- Jitarll},is
20 compared to a predetermined misfit threshold Thmsifit. The predetermined
misfit threshold Thmsillt can be based on the pmticular properties of the ranging
tool 26, accuracy requirements, noise conditions, etc., and can be
predetermined by one skilled in the mi to indicate when an acceptable solution
is found. Where min{IIJirec- Jitarll} for the estimated number ofwellbores
25 Npipe is not less than the predetermined misfit threshold Thmsifit, the procedure
100 proceeds to step 112 where the estimated number of wellbores N"ipe is
incrementally increased. For example, the estimated number of wellbores
N"'P' is increased by one (1 ).
Next, in step 114, the increased estimated number of well bores N"ipe is
30 compared to the maximum number of well bores N'"ax that are locatable by the
system SO.The maximum number of well bores Nmax can be a function of the
- 16-
number of receivers N'·ec provided on the ranging tool 26 as indicated above
with reference to equations (7) and (9). If the increased estimated number of
well bores N'ipe is greater than the maximum number of well bores N"'"X, it can
be concluded that no valid solutions exist using the procedure 100, and the
5 procedure I 00 proceeds to step 116 where the procedure 100 ends.
If the increased estimated number of well bores N'ipe is not greater than
the maximum number of well bores N"'"X, the procedure I 00 retums to step 108
where the parameter set satisfYing min{lli1rec- j{torli} for the increased
estimated number of well bores N"ipe is selected. The steps 108 through 114
10 can be repeated until it is determined in step 11 0 that the difference between
the received magnetic field j[rec and the forward model magnetic field jffor
determined for the selected parameter set is less than the predetermined misfit
threshold Tmisfit. Then, it can be concluded that the selected parameter set
represents a valid solution, and the procedure I 00 proceeds to optional step
15 118. In step 118, the individual contributions of each of the Npipe wellbores
represented in the selected parameter set are calculated and compared to the
predetermined field threshold Thfield. If any of the individual contributions are
determined to be negligible, (less than the predetermined field threshold
Thfield) the wellbores making the negligible contributions can be discarded or
20 disregarded. In some example embodiments, the individual contributions may
be extracted from the calculations performed in step 108 for calculating the
forward model magnetic field jffor. In some instances, step 118 can result in
each of the N'ipe wellbores being disregarded. For example, each individual
wellbore can make a contribution that is Jess than the predetermined field
25 threshold Thfield, while the combined is greater than the predetermined field
threshold Thfield
Then the procedure 1 00 can proceed to step 120 where the nonnegligible
solutions can be returned. The solutions returned can include, for
example, the vector parameter riand/or the vector parameter 4 for each
30 wellbore making a non-negligible contribution. In some embodiments,
parameters such as the cunent magnitude, azimuth angle and the orientation of
the wellbores can be measured or determined from the selected parameter set
- 17-
5
by the data processing unit 64, and these parameters can be retumed as
solutions. In some exemplary embodiments, the solutions can be returned to
the visualizing unit 60 for evaluation by a user, or to any other component of
system 50.
Refening now to FIG. 58, and with continued reference to FIGS. 2 and
4, an exemplary embodiment of an operational procedure 200 for forming a
wellbore in a geologic formation "G" is described. The procedure 200 begins
at step 202 where, a first well bore 12 is identified extending along a first path.
The first well bore 12 can be an existing well bore identified in a crowded field,
10 or the first well bore 12 can be drilled using any drilling method recognized in
the art. A first electrical current letft can then be induced in the first well bore
and a second current Ieffzcan be induced in the second wellbore 14 (step 204).
In some embodiments, the tirst and second electrical cunents letft and letfz
can be excited remotely, e.g., with transmitters 52 of ranging tool 26. Thus,
15 the second current letfz can be excited in the second wellbore 14 without
expressly identifying the location or verifying the existence of the second
wellbore 14. In other embodiments, the first and second cunents lefft and
Ieffz can be directly excited by current source 32 (FIG. 1) at the surface
location "S." In one or more embodiments, the first and second cunents Iefft
20 and Ieffz can be excited at a different point within procedure 200, and the first
and second currents letft and letfz can be maintained continuously or
continually throughout the procedure 200.
At step 206, a third path can be defined having a predetetmined
relationship to the first path is defined. In one or more exemplary
25 embodiments, the third path can be generally parallel to the first path, e.g.,
when the first and third wellbores comprise an SAGD patr. In other
embodiments, the predetermined relationship can be an intersecting
relationship where the third wellbore intersects the first wellbore at a
predetermined or true depth, a lateral branching relationship where the third
30 wellbore branches from the first wellbore at a predetermined location. A
number of well bores N";pe nearby at least a portion of the third path can be
- 18-
estimated to determine a sufficient number of receivers N.,,. for locating the
estimated number of nearby wellbores N'ipe. The sufficient number of
receivers can be determined, e.g., from equations (7) and (9) above, and in
some embodiments is at least five (5) times the estimated number of nearby
5 well bores N'1
P'. A ranging tool 26 including the sufficient number of receivers
54 can be provided in a drill string 18 (FIG. 1 A).
Next in step 208, the drill string 18 can be employed to begin drilling
the third wellbore 16 along the third path. When the ranging tool 26 is
disposed at a first operational position within the third wellbore 16, the
10 received magnetic field Jireccan be detected with the receivers 54, and the
~ received magnetic field H'eccan be communicated to the data processing unit
64 (step 210).
Next, at step 212, the data processing unit 64 can perform procedure
100 (FIG. SA) to determine a number of well bores N"1
P' contributing to the
15 received magnetic field Jirec at the first operational position. The data
processing unit 64 can thereby determine the location of at least the first
wellbore 12with respect to the third wellbore 16. The location of the first
wellbore 12 is returned, and can be used to adjust a direction of drilling to
maintain the path of the third well bore 16 in the predetermined relationship
20 with the first path of the first wellbore 12 (step 214).
Next the procedure 200 returns to step 210 where the ranging tool 26
can again receive a received magnetic field J1rec from a second operational
position along the third path. The procedure 200 can repeat steps 210 through
214 until the third wellbore 16 is complete, and close tolerances can be
25 maintained even when the number of well bores N'1
P' making a non-negligible
contribution to the received magnetic field changes along the third path.
Referring now to FIGS. 6 through 9B, one example of a
mathematically simulated a two-wellbore system 300 is illustrated. A first
wellbore 302 (Pipe 1) and a second well bore 304 (Pipe 2) are simulated in a
30 common plane designated by axes x and y. Currents I1 and h are simulated in
generally opposite directions along the first and second paths defined by the
- 19-
5
first and second wellbores 302, 304 as illustrated by arrows 306 and 308. The
simulated currents I 1 and I2 each have a magnitude l Amp. A third path 310 is
also illustrated between the first and second wellbores 302, 304 along which
ranging tool 26 (FIG. 7) is moved.
As illustrated in FIG. 7, the ranging tool 26 is simulated as including 4
tri-axial receivers 312a, 312b, 312c and 312d disposed symmetrically around
reference point "P ." The tri-axial receivers 312a, 312c are separated along the
y-axis by 20ft., and the tri-axial receivers 312b, 312d are separated along the
x-axis by 20 ft. The reference point "P" at the center of the tri-axial receivers
10 312a, 312b, 312c and 312d was simulated to move along the third path 310
illustrated in FIG. 6.
At a plurality of operational locations along the third path 310, a
forward model magnetic field1f!orwas calculated induced by the first and
second currents I1 and I2for each of the receivers 312a, 312b, 312c and 312d.
15 To simulate a received magnetic field j[rec, a one percent 1% multiplicative
enor with uniform distribution was added to the calculated forward model
magnetic field jffor for each of the receivers 312a, 312b, 312c and 312d at each
of the operational locations along the third path 310. Once the received
magnetic field j[rec was simulated, the system of equations illustrated by
20 equations (2) through (5) were solved as described above with reference of to
step 108 of procedure I 00 (FIG. SA). Since the number of simulated
wellbores was known, the variable N'ipe was defined as two (2), and the
iterative process of steps 110, 112, and 114 were not necessary for
determining the number of nearby wellbores.
25 The parameter set satisfying min{ll1frec- jftorll} for an N"ipe of two
(2) wellbores was determined and the locations of the first and second
wellbores 302, 304 were extracted therefrom for each of the operational
locations. The extracted locations are plotted in FIG. 8 along the simulated
first and second paths for the first and second wellbores 302, 304. The
30 extracted locations for the first well bore 302 are illustrated as asterisks and the
extracted locations for the second wellbore 304 are illustrated as diamonds.
- 20-
As illustrated in FIG. 8, the extracted locations are more accurate where the
third path 310 of the ranging tool 26 (is relatively close to the first and second
wcllbores 302, 304 (toward the right of the graph). In this example, the
accuracy is particularly high where the ranging tool 26 is closer than a radial
5 distance "R" of about 61 meters (about 200 feet). This range is relatively
important for well avoidance and intersection purposes.
As illustrated in FIGS. 9A and 9B, currents were also extracted from
the parameter set found to satisfy min{jjflrec- fltorll}. Again, in FIGS. 9A
and 9B, the x-axis represents the position of the respective wellbores along the
10 x-axis direction. The y-axis represents the magnitude of the extracted
cuncnts. The current magnitudes illustrated are closest to the I Amp
magnitude of the first and second cunents It and h (FIG. 6) where the ranging
tool 26 is simulated to be closest to the simulated wellbores (toward the right
of the graphs). Again, the accuracy is illustrated to be relatively high in a
15 range where accuracy is relatively impmtant for well avoidance and well
intersection purposes.
In one aspect of the disclosure, a method of locating multiple well bores
includes (a) exciting a first electrical current in a first wellbore, (b) exciting a
second electrical current in a second wellbore, (c) disposing a ranging tool at a
20 remote location with respect to the first and second well bores, (d) receiving
and detecting a magnetic field at the remote location with receivers provided
on the ranging tool, and (e) measuring at least one wellbore parameter of each
of the tirst well bore and the second well bore from the magnetic field received
by the ranging tool.
25 In some exemplary embodiments, the at least one wellbore parameter
includes at least one of the group consisting of the first electrical cunent, the
second electrical CU!Tent, a distance of either of the first and second well bores
ti·om the receivers, azimuth angle of either of the tirst and second well bores,
and an orientation of first and second wellbores. The at least one wellbore
30 parameter can include a magnitude of least one of the first current and the
second current.
- 21-
In one or more exemplary embodiments, the method further includes
determining that the received magnetic field is greater than a predetetmined
field threshold. The method may also include calculating a contribution of
each of the first and second to well bores to the received magnetic field, and
5 determining that the contribution of at least one of the first and second
well bores is greater than the predetermined field threshold.
In some exemplary embodiments, the method further includes
determining from the received magnetic field a number of wellbores
contributing to the received magnetic field. The method may also include
10 determining from the received magnetic field that the number of wellbores
contributing to the magnetic field received by the ranging tool is greater than
two and measuring from the received magnetic field at least one wellbore
parameter of at least one well bore other than the first well bore and the second
wellbore. The method can include detennining that the contribution of the at
15 least one well bore other than the first wellbore and the second wellbore to the
received magnetic field is greater than a predetermined threshold value.
In some exemplary embodiments, determining the number ofwellbores
contributing to the magnetic field may include (a) estimating the number of
well bores to define an estimated number of well bores, (b) calculating at least
20 one parameter set for the estimated number of well bores which would produce
the received magnetic field, (c) determining a forward model magnetic field
for each parameter set calculated for the estimated number of well bores, (d)
selecting the parameter set of the at least one parameter set for which a
difference between the received magnetic field and the forward model
25 magnetic field is the least, and (e) detem1ining that the difference between the
received magnetic field and forward model magnetic field for the selected
parameter set is less than a predetermined misfit threshold.
In one or more embodiments, the method may further include
detctmining that the difference between the received magnetic field and
30 forward model magnetic field is not less than the predetetmined misfit
threshold and incrementally increasing the estimated number of wellbores.
The method may also include determining that the incrementally increased
- 22-
estimated number of wellbores is not greater than a max1mum number of
well bores, wherein the maximum number of well bores is based on a number
of receivers provided on the ranging tool. In some exemplary embodiments
the method 11trther includes determining that a magnitude of the received
5 magnetic field is greater than a predetermined field threshold, wherein the
field threshold is selected based on an accuracy of the receivers in detecting a
magnetic field strength. The method may include selecting the predetermined
misfit threshold based on prope1ties of the ranging tool and accuracy
requirements for the measurement of the at least one wellbore parameter of
10 each of the first well bore and the second well bore.
In some exemplary embodiments, disposing the ranging tool at a
remote location includes deploying the ranging tool on a drill string within a
third wellbore, wherein measuring at least one wellbore parameter comprises
measuring a distance of at least one of the first and second well bores from the
15 receivers, and wherein the method fmiher comprises directionally drilling the
third wellbore in a predetermined relationship with respect to at least one of
the first and second wellbores. The predetermined relationship may include at
least one of a parallel relationship, a non-intersecting relationship, an
intersecting relationship, and a laterally branching relationship.
20 In some exemplary embodiments, the first and second currents are
excited at the same fi·equency, and the received magnetic field is received by
an array of single axis magnetometers located in a third wellbore. In some
embodiments, the aJTay of single axis magnetometers may include eight (8)
magnetometers, and the eight (8) magnetometers may be staggered along an
25 axis of the ranging tool. In other exemplary embodiments, an anay of single
axis magnetometers is provided for receiving the received magnetic field,
where the number of single axis magnetometers in the array is at least two (2)
less than three times an estimated number of nearby well bores (i.e., w·ec'?.fYPipe
-2)at the remote location with receivers provided on the ranging tool.
30 In some exemplary embodiments, the first and second wellbores are an
injector and producer respectively of an SAGD pair. In some embodiments,
the first wellbore is a producer of a first SAGD pair, and the second well bore
- 23-
is a producer of a second SAGD pmr. In some embodiments, the first
wellbore is an injector of a first SAGD pair and the second wellbore is a
producer of a second SAGD pair. In some embodiments, the first well bore is
an injector of a first SAGD pair and the second wellbore is an injector of a
5 second SAGD pair. In some embodiments, the first wellbore is a producer of
an SAGD pair, and the second wellbore is a lateral wellbore branching from
the first well bore.
According to another aspect of the disclosure a method of forming a
well bore in a geologic formation includes (a) identifying a first wellbore in the
10 geologic formation along a first path, (b) exciting a first electrical current
along the first path in the first well bore and a second electrical current along a
second path in a second wellbore, (c) drilling a third well bore along a third
path having a predetermined relationship to the first path, (d) detecting a
received magnetic field in the third well bore, ( e )dete1mining from the received
15 magnetic field a number of wellbores contributing to the received magnetic
field, (f) determining a location of the first wellbore based on the number of
well bores determined to be contributing to the received magnetic field, and(g)
adjusting a direction of drilling of the second wellbore to maintain the third
path in the predetermined relationship to the first path.
20 In one or more exemplary embodiments, determining the number of
wellbores contributing to the magnetic field includes (a) estimating the
number of wellbores to. define an estimated number of wellbores, (b)
calculating at least one parameter set for the estimated number of wellbores
which would produce the received magnetic field, (c) detennining a forward
25 model magnetic field for each parameter set calculated for the estimated
number of wellbores, (d) selecting the parameter set of the at least one
parameter set for which a difference between the received magnetic field and
the forward model magnetic field is the least, and (e) determining that the
diflerence between the received magnetic field and loiwm·d model magnetic
30 field for the selected parameter set is less than a predetermined misfit
threshold. In some embodiments, the determined location of the first wellbore
is a parameter in the selected parameter set.
- 24-
In some exemplary embodiments, the method further includes
estimating the number of wellbores to be determined from the received
magnetic field and deploying a ranging tool having Nrec single axis receivers
where N·cc is at least five times greater than an the estimated number of
5 well bores. In some exemplary embodiments, the predetermined relationship is
a generally parallel relationship wherein one of the first and third well bores is
shallower than the other of the first and third well bores such that the first and
second wellbores together define an SAGD pair.
In another aspect of the disclosure, a system for locating multiple
10 wcllbores include (a) a non-transitory memory having a set of instructions
thereon, wherein the instructions include instructions for accepting a received
magnetic field as input, instructions for detem1ining from the received
magnetic field a number of well bores contributing to the received magnetic
field and instructions for detetmining at least one parameter of each well bore
15 detetmined to be contributing to the received magnetic field; and a processor
for executing the set instructions.
In some exemplary embodiments, the instructions for detetmining the
number of well bores contributing to the received magnetic field may include
instructions for (a) estimating the number of wellbores contributing to the
20 received magnetic field to define an estimated number of wellbores, (b)
calculating at least one parameter set for the estimated number of well bores
which would produce the received magnetic field, (c) determining a forward
model magnetic field for each parameter set calculated for the estimated
number of well bores, (e) selecting the parameter set of the at least one
25 parameter set for which a difference between the received magnetic field and
the forward model magnetic field is the least, and (f) determining whether the
ditTerence between the received magnetic field and forward model magnetic
field for the selected parameter set is less than a predetermined misfit
threshold.
30 ln one or more exemplary embodiments, the system fmther includes a
drill string m1d ranging tool carried by the drill string. In some embodiments,
the ranging tool may include a receiver operable to detect and measure the
- 25-
received magnetic field, and the ranging tool may be communicatively
coupled to the processor. In some exemplary embodiments, the ranging tool
may further include a transmitter operable to generate an electromagnetic
probe signal that causes current to flow in electrically conductive bodies
5 exterior to the transmitters to thereby generate the received magnetic field.
10
15
Also, in some exemplary embodiments, the system may futiher include a
transmitter deployed independently of the ranging tool into a first well bore of
a SAGO pair of well bores, and the drill string may be deployed into a second
wellbore of the SAGO pair.
Moreover, any of the methods described herein may be embodied
within a system including electronic processing circuitry to implement any of
the methods, or a in a computer-program product including instructions which,
when executed by at least one processor, causes the processor to perform any
of the methods described herein.
The Abstract of the disclosure is solely for providing the United States
Patent and Trademark Office and the public at large with a way by which to
determine quickly from a cursory reading the nature and gist of technical
disclosure, and it represents solely one or more embodiments.
While various embodiments have been illustrated in detail, the
20 disclosure is not limited to the embodiments shown. Modifications and
adaptations of the above embodiments may occur to those skilled in the art.
Such modifications and adaptations are in the spirit and scope of the
disclosure.
- 26-
5
WE CLAIM:
1. A method of locating multiple well bores, comprising:
exciting a first electrical cutTent in a first well bore;
exciting a second electrical current in a second well bore;
disposing a ranging tool at a remote location with respect to the first
and second well bores;
receiving and detecting a magnetic field at the remote location with
receivers provided on the ranging tool; and
measuring at least one well bore parameter of each of the tirst well bore
10 and the second wellbore from the magnetic field received by the ranging tool.
2. The method of claim 1, wherein the at least one well bore parameter
comptises at least one of the group consisting of the first electrical current, the
second electrical cul1'cnt, a distance of either of the first and second well bores
from the receivers, azimuth angle of either of the first and second well bores,
15 and an orientation of first and second well bores.
3. The method of claim 2, wherein the at least one wellbore parameter
comprises at least one of the first cul1'ent and the second current.
4. The method of claim 1, further comprising determining that the
received magnetic field is greater than a predetermined field threshold.
20 5. The method of claim 4, further comprising:
calculating a contribution of each of the first and second to well bores
to the received magnetic field; and
determining that the contribution of at least one of the first and second
well bores is greater than the predetermined field threshold.
- 27-
6. The method of claim I, further comprising determining from the
received magnetic field a number of wellbores contributing to the received
magnetic field.
7. The method of claim 6, wherein detennining the number of well bores
5 contributing to the magnetic tleld comprises:
estimating the number of well bores to define an estimated number of
well bores;
calculating at least one parameter set for the estimated number of
well bores which would produce the received magnetic field;
10 determining a forward model magnetic tield for each parameter set
15
calculated for the estimated number of well bores;
selecting the parameter set of the at least one parameter set for which a
difference between the received magnetic field and the forward model
magnetic field is the least; and
determining that the difference between the received magnetic field
and forward model magnetic field for the selected parameter set is less than a
predetermined misfit threshold.
8. The method of claim 7, fmiher comprising:
dete1mining that the difference between the received magnetic field
20 and forward model magnetic tleld is not less than the predetermined mistit
threshold; and
incrementally increasing the estimated number of well bores.
9. The method of claim 8, further compnsmg determining that the
incrementally increased estimated number of wellbores is not greater than a
25 maximum number of well bores, wherein the maximum number of well bores is
based on a number of receivers provided on the ranging tool.
- 28-
5
10. The method of claim 7, further compnsmg detem1ining that a
magnitude of the received magnetic field is greater than a predetennined tield
threshold, wherein the predetermined field threshold is selected based on an
accuracy of the receivers in detecting a magnetic field strength.
11. The method of claim 7, further comprising selecting the predetermined
mistit threshold based on properties of the ranging tool and accuracy
requirements for the measurement of the at least one wellbore parameter of
each of the tirst wellbore and the second wellbore.
12. The method of claim 1, wherein disposing the ranging tool at a remote
10 location comprises deploying the ranging tool on a drill string within a third
wellbore, wherein measuring at least one wellbore parameter comprises
measuring a distance of at least one of the first and second well bores from the
receivers, and wherein the method further comprises directionally drilling the
third wellbore in a predetermined relationship with respect to at least one of
15 the first and second well bores.
13. The method of claim 12, wherein the predetermined relationship
includes at least one of a parallel relationship, a non-intersecting relationship,
an intersecting relationship, and a laterally branching relationship.
14. A method of fmming a wellbore in a geologic fommtion, the method
20 comprising:
25
identifying a first well bore in the geologic formation along a first path;
exciting a first electrical current along the tirst path in the first
wellbore and a second electrical cull'ent along a second path in a second
well bore;
drilling a third wellbore along a third path having a predetermined
relationship to the first path;
detecting a received magnetic field in the third wellbore;
- 29-
5
determining from the received magnetic field a number of wellbores
contributing to the received magnetic field;
determining a location of the first wellbore based on the number of
well bores detem1ined to be contributing to the received magnetic field; and
adjusting a direction of drilling of the second well bore to maintain the
third path in the predetermined relationship to the first path.
15. The method of claim 14, wherein determining the number ofwellbores
contributing to the magnetic field comprises:
estimating the number of well bores to define an estimated number of
10 wellbores;
15
calculating at least one parameter set for the estimated number of
well bores which would produce the received magnetic field;
determining a forward model magnetic field for each parameter set
calculated for the estimated number of well bores;
selecting the parameter set of the at least one parameter set for which a
difference between the received magnetic field and the forward model
magnetic field is the least; and
determining that the difference between the received magnetic field
and forward model magnetic field for the selected parameter set is less than a
20 predetermined misfit threshold.
16. The method of claim 15, wherein the determined location of the first
well bore is a parameter in the selected parameter set.
17. The method of claim 14, further comprising:
estimating the number of well bores to be determined from the received
25 magnetic field; and
deploying a ranging tool having N""" single axis receivers where N·ec is
at least five times greater than an the estimated number ofwellbores.
- 30-
5
18. The method of claim 14, wherein the predetermined relationship is a
generally parallel relationship wherein one of the first and third well bores is
shallower than the other of the first and third wellbores such that the first and
second well bores together define a SAGD pair.
19. A system for locating multiple well bores, comprising:
a non-transitory memory having a set of instructions thereon, the
instructions including instructions for accepting a received magnetic field as
input, instructions for determining fi·om the received magnetic field a number
of wellbores contributing to the received magnetic field and instructions for
10 determining at least one parameter of each wellbore determined to be
contributing to the received magnetic field; and
a processor for executing the set instructions.
20. The system of claim 19, wherein the set of instructions for determining
the number of well bores contributing to the received magnetic field includes
15 instructions for:
20
estimating the number of wellbores contributing to the received
magnetic field to define an estimated number of well bores;
calculating at least one parameter set for the estimated number of
well bores which would produce the received magnetic field;
dete1mining a forward model magnetic field for each parameter set
calculated for the estimated number ofwellbores;
selecting the parameter set of the at least one parameter set for which a
difference between the received magnetic field and the forward model
magnetic field is the least; and
25 determining whether the difference between the received magnetic
field and forward model magnetic field for the selected parameter set is less
than a predetermined misfit threshold.
- 31-FIELD OF THE INVENTION
The present disclosure relates generally to making measurements
related to oil and gas exploration. More particularly, embodiments of the
5 disclosure relate to systems and methods for measuring electromagnetic fields
to detect a number of nearby wellbores, and to determine the locations of the
nearby well bores.
BACKGROUND
In drilling wells for oil and gas exploration, understanding the structure
10 and properties of the associated geological formation provides information to
aid such exploration. In addition, drilling can be enhanced with systems and
methods to detect conductive bodies below the earth's surface. The conductive
bodies can include metal structures, e.g., casing and piping used in various
down-hole operations, where the detection of the metal structures can reveal
15 subtetTanean positions of existing wellbores. For example, the positions of
existing wellbores can influence drilling operations in crowded fields where
legal or land restrictions require wells to be drilled in close proximity with one
another. In some instances, well avoidance is an important consideration in
drilling in the crowded fields, and in some instances, well intersection can be
20 intentional, e.g., for the repair of a damaged well bore.
In other instances, determining the position of existing well bores can
facilitate drilling a wellbore in a predetermined relationship to the existing
wellbore. For example, in steam assisted gravity drainage (SAGD)
applications, a wellbore is often drilled parallel to existing wellbores.
25 Generally in SAGD applications, steam is used in conjunction with two spaced
apati well bores( an SAGD pair) to address the mobility problem of heavy oil in
a fonnation. High temperature steam may be injected into an upper wellbore
(the injector), and used to heat the heavy oil to reduce its viscosity and thereby
enhance the flow of the heavy oil into a lower wellbore (the producer)to
30 enhance extraction of the heavy oil. Preferably, the injector and producer are
drilled at a distance of only a few meters from one other, e.g., about 5 to about
- 2 -
15 meters. If the injector is positioned too close to the producer, the producer
would be exposed to very high pressure and temperature and steam would be
directly communicated to the producer. If the injector is positioned too far
fl·om the producer, the efficiency of the SAGD process is reduced. In order to
5 assist in ensuring that the injector of an SAGD pair is positioned as desired
relative to the producer well bore, a survey of the geologic formation is often
conducted. These surveying techniques are traditionally referred to as
"ranging." Often, these ranging techniques can be frustrated by the proximity
of multiple nearby well bores, e.g., where it can be difficult to distinguish
10 magnetic fields contributed from a target wellbore from other nearby existing
well bores in a crowded tield.
BRIEF DESCRIPTION OF THE DRAWINGS
The disclosure is described in detail hereinafter on the basis of
embodiments represented in the accompanying figures, in which:
15 FIG. lA is a cross-sectional schematic side-view of a system of
wcllbores including first and second existing wellbores and a third wellbore
having a drill string or other conveyance equipped with a ranging tool
disposed therein in accordance with one or more exemplary embodiments of
the disclosure;
20 FIG. lB is a cross-sectional schematic top-view of the system of
well bores of FIG. I A illustrating a crowded field of existing well bores
proximate the first, second and third well bores;
FIG. 2 is a schematic diagram of system for determining the number
and locations of multiple well bores including receivers of the ranging tool of
25 FIG. lAin accordance with example embodiments of the disclosure;
FIG. 3 is a schematic view of the ranging tool and the first well bore of
FIG. !A illustrating various parameters of the first wellbore that are
determinable by the system of FIG. 2;
FIG. 4 is a schematic view of the ranging tool and multiple well bores
30 of the network of FIG. I A illustrating magnetic fields detectable by the
ranging tool;
- 3 -
FIGS. SA and SBare flowcharts illustrating operational procedures that
include locating multiple wellbores in accordance with example embodiments
of the disclosure;
FIG. 6 is a graphical view of a mathematically simulated example of a
5 two-wellbore system illustrating simulated location curves for first and second
well bores and a simulated path of a ranging tool for detennining the respective
locations of the first and second well bores using an inversion portion of the
operational procedure illustrated in FIG. SA;
FIG. 7 is a schematic view of a sensor anangement for the ranging tool
10 of FIG. 6;
FIG. 8 is a graphical view of the simulated two-wellbore system of
FIG. 6 illustrating positional data points calculated for the first and second
well bores overlying the respective simulated location curves; and
FIGS. 9A and 9B are graphical views illustrating data indicative of a
15 current magnitude calculated for a simulated cUtTent of 1 Amp flowing
respectively through the first and second wellbores of FIG. 6.
DESCRIPTION OF INVENTION w.r.t. DRAWINGS
In the interest of clarity, not all features of an actual implementation or
method are described in this specification. Also, the "exemplary"
20 embodiments described herein refer to examples of the present invention. In
the development of any such actual embodiment, numerous
implementation-specific decisions may be made to achieve specific goals,
which may vary from one implementation to another. Such would
nevertheless be a routine undertaking for those of ordinary skill in the art
25 having the benefit of this disclosure. Further aspects and advantages of the
various embodiments and related methods of the invention will become
apparent from consideration of the following description and drawings.
The present disclosure may repeat reference numerals and/or letters in
the various examples. This repetition is for the purpose of simplicity and
30 clarity and does not in itself dictate a relationship between the various
embodiments and/or configurations discussed. Further, spatially relative
- 4-
tenns, such as "below," "upper," "up-hole," "down-hole," and the like, may
be used herein for ease of description to describe one element or feature's
relationship to another element(s) or feature(s) as illustrated in the figures.
The spatially relative terms are intended to encompass different orientations of
5 the apparatus in use or operation in addition to the orientation depicted in the
figures.
Figure I illustrates a multi-wellbore system 10 including a first
wellbore 12 and a second wellbore 14 formed in a geologic formation "G." In
some exemplary embodiments, the geologic formation "G" is an oil sand or
10 other heavy oil formation disposed at a relatively shallow depth, e.g., 70-600
m below a surface location "S." The first and second wellbores 12, 14 can be
employed for recovery of heavy oil from the geologic formation "G" using
processes such as SAGO operations. The systems and methods, in accordance
with the teaching herein, can be used to provide SAGO steering, and such
15 SAGO steering can be applied to non-horizontal wells as well. Although the
multi-wellbore system I 0 is described herein below as employed in
conjunction with SAGO operations, it should be appreciated that aspects of
disclosure may be practiced in conjunction with offshore ranging operations or
other types of exploration as well.
20 The first and second wellbores 12, 14 include respective electrically
conductive bodies 12a, 14a therein. The electrically conductive bodies 12a,
14a can include strings of casing pipe, production tubing or other elongate
metallic media in which electrical currents can be excited. As described in
greater detail below, electrical cutTents excited in the electrically conductive
25 bodies 12a, 14a in the first and second wellbores 12, 14 can facilitate magnetic
ranging processes for drilling a third wellbore 16 along a path having a
predetermined relationship with a path defined by the first wellbore 12. The
predetermined relationship can include, e.g., a generally parallel, horizontal
relationship to facilitate SAGO operations. By allowing two or more
30 wellbores 12, 16 to be positioned within extremely tight tolerances, magnetic
ranging technology can help eliminate positional uncertainty of conventional
surveys and can provide more precise tolerance for SAGO wells. In other
- 5-
embodiments, the predete1mined relationship can be an intersecting
relationship where the third wellbore 16 intersects the first wellbore 12 at a
predetermined and/or true depth, a lateral branching relationship where the
third wcllbore 16 branches from the first wellbore 12at a predetermined
5 location.
The first wellbore 12 can be employed as the "producer" in a SAGD
system and the third well bore 16 can be employed as the "injector" in a SAGD
system. The third well bore 16 is being drilled proximate the first wellbore 12
at a distance "D" theretl·om. In some example embodiments, the distance "D"
10 can be in the range of about 5 to about 15 meters. The third wellbore 16 is
being drilled with a drill string 18 having a drill bit 20 at a lower end thereof.
A slant drilling rig 22 is erected at the surface location "S" to support the drill
string 18 at shallow angles, e.g., at angles in the range of about !5° to about
75° from horizontal. In some example embodiments, the slant drilling rig 22
15 can support the drill string 18 at angles of between 0° and 90° (inclusive) from
horizontal. Often slant drilling is employed to facilitate access to the shallow
geologic fmmations "G" where heavy oils are entrapped and SAGD
operations are generally conducted.
A ranging tool 26 is calTied by the drill string 18. The ranging tool 26
20 can be employed to determine the location of the conductive body 12a within
the first wellbore 12, thus permitting the drill bit 20 to be steered to maintain
the third wellbore 16 at the distance "D" from the first wellbore 12, or at any
spatial relationship therewith. As described in greater detail below, the
ranging tool 26 is operable to detect a magnetic field generated by separate
25 electric cu!Tents propagated through electrically conductive bodies 12a, 14a,
and measure wellbore parameters of both the first and second wellbores 12, 14
to guide the drill string 18. In some example embodiments, the ranging tool
26 can be deployed independently of a drill string 18. For example, the
ranging tool 26 can be deployed into an additional existing wellbore (not
30 shown) by wireline, coiled tubing or other recognized methods. Alternatively
or additionally, the ranging tool 26 can be deployed by moving the ranging
tool 26 across the surface location "S."
- 6-
The electric currents propagated through the conductive bodies 12a,
14a can be excited in any recognized manner, e.g., by using a down-hole
electrode source 30, or by directly coupling an electrically conductive body
12a to a current source 32 at the surface location "S." In some example
5 embodiments, the currents can be remotely excited by coil antennas 34, which
form a pmi of, or are carried by, the drill string 18. In some embodiments, the
electrical currents can be excited by the transmitters 52 (FIG. 2) provided in
the ranging tool 26.
Referring to FIG. 1 B, in some example embodiments, the first well bore
10 12 in the multi-wellbore system 10 can have a plurality of"fishbone" or lateral
wellbores 12' branching therefrom. The lateral wellbores 12' can permit
production from a wider expanse of the geologic formation "G" than through
the first wellbore 12 alone. Similarly, the second wellbore 14 can include
lateral well bore 14' branching therefrom. Additional well bores 36a through
15 36c are drilled in the vicinity of the first and second wellbores 12, 14 and
together with the respective lateral well bores 36a' through 36c', the wellbores
12, 14 and 36a through 36c can produce from a relatively large horizontal area
of the geologic formation "G." Each of the well bores 12, 14and 36a through
36c can be drilled from a relatively small, common drilling area 40. The field
20 of wellbores defined by the wellbores 12, 14 and 36a through 36c can be
characterized as a crowded field, particularly near the common drilling area
40.As the third well bore 16 is drilled through the crowded field, e.g., from the
drilling area (point A) to a te~minal end (point B), the number of "nearby"
well bores t!·equently changes. As used herein, a "nearby wellbore" includes at
25 least a well bore having a current excited therein that produces a magnetic field
detectable by a ranging tool 26. Each one of the well bores 36a through 36c,
and each of the respective lateral wellbores 36a' through 36c' can also include
an individual electrically conductive body (not explicitly shown) therein that
can generate a magnetic field detectable by the ranging tool 26. Thus,
30 accurately interpreting the electromagnetic field received and detected by the
ranging tool 26 at any particular location can include detetmining a number of
well bores making a contribution to the received electromagnetic field.
- 7-
Refening to FIG. 2 and with continued reference to FIGS. !A and IB,
a system 50 for determining the number, locations and/or other wellbore
parameters of multiple wellbores is illustrated. The system 50 can include
transmitters 52 and receivers 54. In some example embodiments, the
5 transmitters 52 can form a part of the ranging tool 26, and can be carried by a
drill string 18 (FIG. 1 A). The transmitters 52 can be operable to generate an
electromagnetic probe signal that causes current to flow in the electrically
conductive bodies 12a, 14a (FIG. !A). In some example embodiments, the
transmitters 52 can include a focused electric dipole source operable to induce
10 the electric current in the electrically conductive body 16, which is exterior to
the structure of the transmitters 52. In some example embodiments, the
transmitters 52 can be deployed independently of the ranging tool 26, e.g., by
wireline into an adjacent wellbore 36b, or can be mounted at stationary
location with respect to the geologic formation "G." As used herein, the term
15 "transmitter" car1 include other such mechanisms for inducing the electric
currents in the electrically conductive bodies 12a and 14c (FIG. !A) such as
the electrode 30 and/or cunent source 32.
The receivers 54 may include any mechanism that detects, measures
and/or collects a magnetic field for processing. For example, coil antennas or
20 magnetometers can be used. The receivers 54 ca11 be operable to measure or
collect for processing an electromagnetic field emitted from one or more
electrically conductive bodies 16 (FIG. 1 A), as a result of the probe signal
generated from the transmitters 52. The electrically conductive bodies 12a,
14a, and the wellbores 12, 14, 36a through 36c and 36a' through 36c'
25 containing the electrically conductive bodies 12a, 14a, can be detected from
the magnetic field, and the appropriate locations and other wellbore
parameters can be determined therefrom.
The system 50 also includes a communications unit 56, which
facilitates interaction among a system control center 58, a visualizing unit 60
30 and the transmitters 52 and receivers 54. The communications unit 56 can
provide a bi-directional telemetry system for communication between downhole
components, e.g., the ranging tool 26, and components located at the
- 8-
surface location "S," e.g., the visualizing unit 60. Communications unit 56
can employ combinations of wired communication technologies and wireless
teclmologies at frequencies that do not interfere with on-going measurements
made by the ranging tool 56. The visualizing unit 60 can include computer
5 monitors, printers or other devices that pennit an operator at the surface
location "S" to monitor data generated by the system 50. The operator may
monitor the data to determine whether intervention into the system 50 is
necessary.
The system control center 58 can be disposed within the ranging tool
10 26, at another down-hole location, or at the surface location "S," and can
include a computer with a processor and a non-transitory memory associated
therewith. The system control center 58 can manage the generation of
transmission signals, e.g., instmctions signals for the transmitters 52, and can
manage the collection of received signals, e.g., data signals from the receivers
15 54, cmTesponding to the transmission signals. The frequency at which the
transmission signals are provided can be controlled by the system control
center 58. The system control center 58 is also operably coupled to a data
acquisition unit 62 and a data processing unit 64. The data acquisition unit 62
can include analog to digital conve1iers, or other mechanisms for converting
20 the received signals into a form useable by the system control center 58 and/or
the data processing unit 64.
The data processing unit 64 can convert the received signals into
information indicating the number, position and directional characteristics of
well bores in the vicinity of the ranging tool 26 as described in greater detail
25 below. This infonnation can be provided to the visualizing unit 60 for
evaluation by an operator. In some embodiments, the data processing unit 64
may include a processor 64a and a computer readable medium 64b operably
coupled thereto. The computer readable medium 64b can include a
nonvolatile or non-transitmy memory with data and instructions that are
30 accessible to the processor 64a and executable thereby. In one or more
embodiments, the computer readable medium 64b is pre-programmed with
predetennined thresholds Thfield and Thmisfit, which, as described in greater
- 9-
detail below, can be at least pmiially dependent on characteristics of the
ranging tool 26. The computer readable medium 64b may also be preprogrmnmed
with predetetmined sequences of instructions for performing
various steps of procedures I 00, 200 described below with reference to FIGS.
5 SA and 5B.
Referring to l'IG. 3, parameters associated with a wellbore, which can
be determined by the data processing unit 64 (FIG. 2) are illustrated. These
parameters include position and direction parameters that can fully define the
location of the wellbore in three-dimensional space. Only the first well bore 12
10 is illustrated in FIG. 3, although, each wellbore in the multi-wellbore system
I 0 can be defined by a similar parameter set.
In one or more embodiments, a wellbore parameter set may include a
vector parameter l;, which represents a current flowing through the wellbore
12 in an axial direction of the wellbore 12, and a vector parameter ri
15 representing an mihogonal distance between the wellbore 12 and a reference
point "P" defined with respect to the ranging tool 26. The reference point "P"
is illustrated at the center of coordinate system 66, and the vector parameters
l;and ri can be directionally defined with respect to the coordinate system 66.
The subscript "i" denotes an index number of the first well bore 12, or more
20 generally, any of the well bores in a multi-wellbore system 10. The index "i"
is an integer ranging from I to N'ipe, where N"ipe is a number of wellbores.
The number of wellbores represented by N"ipe can be a total number of
well bores in a multi-wellbore system I 0, a number of nearby well bores that
make a non-negligible contribution (defined in greater detail below) to the
25 magnetic field detected by the ranging tool 26, or an estimated number of
4 4 wells. Both of the vector parameters /iand rihave three degrees of freedom,
and thus, there are at least six variables or "unknown" parameters in a
parameter set associated with the first well bore 12,and each of the N"ipe wells.
4 4 The vector parameters /iand riare determinable by the system 50, and other
30 parameters such as azimuth angle and orientation of the first well bore 12 can
4 4 be determined from the vector parameters /iand ri. For steering the ranging
- 10-
tool 26 relative to the first wellbore 12, it is not necessarily required to
determine the strength of the current propagated tlu·ough the first wellbore 12,
i.e., the magnitude of current vector I;. However, as described below,
determining the current vector I;can facilitate determining the contribution of
5 the first well bore 12 to a field detected by the ranging tool 26.
As illustrated in FIG. 4, a first magnetic field H1 is induced by the first
effective current lerr1 flowing through the first well bore 12. A second magnetic
field H2 is induced by a second effective current !err, flowing tlu·ough the
second well bore 14. The ranging tool 26 is located at within the third well bore
10 16 at respective radial distances R1 and R2 from the wellbores 12 and 14. The
ranging tool 26 can include receivers 54 in the form of tri-axial coil antennas,
i.e., a set of three antennas whose magnetic moment vectors form an
orthogonal system spanning the entire field. Thus, the ranging tool 26 can be
sensitive to the fields H1 and H2, regardless of the orientation of the fields Ht
15 and H2 with respect to the receivers 54. The combined magnetic field detected
by the ranging tool 26 includes a contribution from each of the fields Ht and
H2. Assuming that the wellbores 12 and 14 are infinitely long, and assuming
that the effective currents lerr1 and Ierr2 are constant, each of the magnetic
fields H1 and H2 can be expressed by equation (I) below.
20
(1)
In equation (I), H denotes the magnetic field,$ is the unit vector in an
azimuthal direction, and ris the position vector for the receivers 54 (FIG. 2) of
the ranging tool 26. Even though equation (I) is used as the basis of the
mathematical formulation presented next, in some exemplary embodiments, is
possible to replace equation (I) with a more precise version of the equation by
25 including the axial variations of the cmTent on a pipe, for example. From
~ equation (I) it is seen that the magnetic field H detected by the ranging tool 26
can be inversely propottional to the radial distances R1 and R2 between the
wellbores 12 and 14and the receivers 54. The assumptions regarding the
infinite lengths and constant currents have generally been demonstrated to
- 11-
yield suftlciently accurate approximations of the wellbore parameters for
steering purposes. In particular, these assumptions yield relatively accurate
approximations of the well bore parameters for well bores nearest the receivers
54 where the radial distances R1 and R2 are the smallest and where accuracy
5 can be relatively significant for steering. The formulation of the magnetic
fields given in equation (I) is thus employed throughout this specification.
However, if different descriptions of the magnetic fields radiated from the
well bores are available; these descriptions may be employed without departing
from the spirit and scope of the present disclosure.
10 When the ranging tool 26 is deployed, each receJVer 54 can make
distinct measurements of the total magnetic fieldH. A number of receivers 54
provided on the ranging tool 26 can be designated as N·ec. In some exemplary
embodiments, at least some of the receivers 54 are single axis magnetometers,
and in some exemplary embodiments, at least some of the receivers 54 are tri-
15 axial or other multi-axial receivers. The number of receivers N'"c can
designate the number of axes along which the receivers are disposed. For
example, where four (4) tri-axial receivers 54 are provided on a ranging tool
26 in various orientations, the number of receivers N·ec can be defined as
twelve (12). Using the formulation for the magnetic fields given in equation
20 (I) above, for each of the N·ec receivers 54, the magnetic field can be described
by one of theN'' cequations illustrated by equations (2) through (3) below.
In equations (2) through (3), Huk generally denotes the magnetic field
measured by the k'" receiver 54 of the ranging tool 26, where k is an index
number ranging from I to N·ec. The variable ilk represents the unit vector in
- 12-
the direction that the /(11 receiver 54 is oriented to receive the magnetic field,
e.g., the magnetic moment vector's direction for a magnetic dipole. The
variable ru~cis the position vector of the !(" receiver 54 with respect to the
reference point "P." These equations indicate that the magnetic field Huk
5 detected by one of the receivers 54 will be a summation of the contributions
made by each of the N"ipe cunents induced in well bores.
In addition to the N·ec equations (2) through (3), another system of
equations can be defined for the wellbore parameters using the assumption that
the direction of the cunent induced in a well bore will be orthogonal to the
10 position vector. As illustrated in the N"ipe equations in equations ( 4) through
(5) below, the inner dot product of the two mthogonal vectors ~ and r; will be
zero.
(4)
(5)
The total number of equations defined by equations 2 through 5 is
(N'""e + N''"') the sum of the number of well bores (N''ipe) and the number of
15 receivers (N''"'). Since there are six "unknown" parameters associated with
each of the N"ipe wellbores as described above, the total number of unknown
parameters, and thus the minimum number of equations necessary for
obtaining an unambiguous solution for the unknown parameters is 6 X
Npipe .Thus, to obtain an unambiguous solution for the unknown wellbore
20 parameters, the relation indicated in relation (6) below should generally be
met. It follows that generally, the number of well bores N"ipe can be a function
of the number of receivers Nrec provided, and a maximum number of well bores
that can be determined unambiguously as illustrated in relation (7).
(6)
. Nrec
=; Nptpe < __ = Nmax
- 5 (7)
-13-
In some instances, where some additional information is available or
can be estimated, a fewer number of receivers Nrec can allow for a greater
number of well bores N"ipe to be located. For example, where it is known, or it
can be estimated, that each of the wellbores in a multi-wellbore system is
5 parallel, the general relations (6) and (7) can be reduced to relations (8) and (9)
below.
Npipe + Nrec ;:: 4 X Npipe + 2 (8)
(Nrec _ 2)
=> Npipe < = Nmax
- 3
(9)
~ This reduction is possible where the direction of each of the currents I;
is known to be the same for each wellbore although the amplitude for each
current l; may be dissimilar. In some embodiments, this infmmation can be
10 known, e.g., in a multi-wellbore system including a one or more parallel of
SAGD pairs.
The number of well bores N"ipe can include a number of well bores that
produce a non-negligible magnetic field at the ranging tool 26. In a crowded
field, such as the field depicted in FIG. JB, contributions from a large number
15 of wellbores may be detected by the ranging tool 26. However, some of these
contributions may be negligible. For example, the attenuation of the magnetic
fields produced by currents induced in wellbores at large distances from the
ranging tool 26 can produce relatively small contributions to the magnetic
fields detected. Also, destmctive interference can produce a cancellation
20 effect on the magnetic fields than can contribute to relatively small
contributions to the magnetic fields detected. The definition of negligibility
can be dependent on several system-dependent characteristics or requirements
such as accuracy, noise floor, etc. A threshold Thfield can be predetermined by
one skilled in the art below which a particular contribution can be considered
25 negligible and removed from further consideration as part of the multiwellbore
system.
Refe11'ing to FIG. SA, and with continued reference to FIG. 2, an
operational procedure I 00 can be employed for locating multiple well bores
- 14-
using the data processing unit 64 of system 50 (FIG. 2). Preconditions for the
procedure I 00 can include that a current is induced in each well bore to be
located, the ranging tool 26 is deployed at a first operational location, and a
received magnetic fieldHr'cfrom the first operational location is detected by
5 the receivers 54 and communicated to the data processing unit 64, which
accepts the received magnetic field ifrec as input. The operational procedure
I 00 begins at step I 02 where the received magnetic field jfrec is received by
the data processing unit and evaluated to determine if the magnitude or norm
of the received magnetic field ifrec is greater than the predetermined field
10 threshold Thfield for negligibility. If the norm of the received magnetic field
ifrec is not greater than the predetermined field threshold Thfield, then it can be
determined that there are no nearby wellbores producing a non-negligible
magnetic field. The procedure I 00 proceeds to step 104 where the procedure
100 may end. Optionally, at the end of the procedure 100, the data processing
15 unit 64 can provide a status to the visualization unit 60, such that a user can be
alerted that no nearby wcllbores were located at the first operational position.
The ranging tool 26 can then be moved to a second operational position, and
the procedure 1 00 can be repeated. The preconditions and post process return
to step 102 where another received magnetic field ifreccan be evaluated.
20 Where it is determined at step I 02 that the norm of the received
magnetic field jfrec is greater than the predetermined field threshold Thfield,
there may be nearby well bores contributing to the received magnetic field ifrec.
The procedure 100 proceeds to step I 06 where an iterative inversion process
can be initiated to determine the number and locations of the contributing
25 well bores. Initially, at step I 06, an estimated number of contributing
well bores can be selected. Generally, an estimate of one (1) can be selected,
although in some exemplary embodiments a higher number of wellbores can
be estimated, e.g., if it is known that a minimum number of wellbores arc
nearby. The variable N'ipe is set to the initial estimate at step I 06.
30 Next, the procedure I 00 proceeds to step I 08 where at least one
parameter set is calculated for the estimated number of well bores Npipe which
- 15-
would produce the received magnetic field Jirec. For example, when the
estimated number of well bores N"ipe is set to one (I), the parameter set for a
single wellbore which would produce the received magnetic field Jirec at the
operational location of the receivers is calculated. The at least one parameter
5 set may include the at least the six unknown parameters associated with the
~ ~ vector parameters /iand r;, and can be calculated by solving the system of
equations defined by equations (2) through (5) described above. Often, this
system of equations will not have a unique solution, and solving the system of
equations yields a plurality of parameter sets. A forward model magnetic field
10 Jifor is determined for each parameter set. The fmward model magnetic
fieldsJifor can be determined by solving equation (2) above. Next, for each
forward model Jifor determined, the nann of the difference between the
received magnetic field Jirec and the forward model magnetic fieldJifor, and the
parameter set producing the minimum value is selected. For example, the
15 parameter set that satisfies min{IIJirec- Jitarll} for the estimated number of
well bores Npipe is selected.
Next, the procedure 100 proceeds to step 110, where the norm of the
difference between the received magnetic field Jirecand forward model
magneticJlfm'for the selected parameter set, i.e., min{IIJirec- Jitarll},is
20 compared to a predetermined misfit threshold Thmsifit. The predetermined
misfit threshold Thmsillt can be based on the pmticular properties of the ranging
tool 26, accuracy requirements, noise conditions, etc., and can be
predetermined by one skilled in the mi to indicate when an acceptable solution
is found. Where min{IIJirec- Jitarll} for the estimated number ofwellbores
25 Npipe is not less than the predetermined misfit threshold Thmsifit, the procedure
100 proceeds to step 112 where the estimated number of wellbores N"ipe is
incrementally increased. For example, the estimated number of wellbores
N"'P' is increased by one (1 ).
Next, in step 114, the increased estimated number of well bores N"ipe is
30 compared to the maximum number of well bores N'"ax that are locatable by the
system SO.The maximum number of well bores Nmax can be a function of the
- 16-
number of receivers N'·ec provided on the ranging tool 26 as indicated above
with reference to equations (7) and (9). If the increased estimated number of
well bores N'ipe is greater than the maximum number of well bores N"'"X, it can
be concluded that no valid solutions exist using the procedure 100, and the
5 procedure I 00 proceeds to step 116 where the procedure 100 ends.
If the increased estimated number of well bores N'ipe is not greater than
the maximum number of well bores N"'"X, the procedure I 00 retums to step 108
where the parameter set satisfYing min{lli1rec- j{torli} for the increased
estimated number of well bores N"ipe is selected. The steps 108 through 114
10 can be repeated until it is determined in step 11 0 that the difference between
the received magnetic field j[rec and the forward model magnetic field jffor
determined for the selected parameter set is less than the predetermined misfit
threshold Tmisfit. Then, it can be concluded that the selected parameter set
represents a valid solution, and the procedure I 00 proceeds to optional step
15 118. In step 118, the individual contributions of each of the Npipe wellbores
represented in the selected parameter set are calculated and compared to the
predetermined field threshold Thfield. If any of the individual contributions are
determined to be negligible, (less than the predetermined field threshold
Thfield) the wellbores making the negligible contributions can be discarded or
20 disregarded. In some example embodiments, the individual contributions may
be extracted from the calculations performed in step 108 for calculating the
forward model magnetic field jffor. In some instances, step 118 can result in
each of the N'ipe wellbores being disregarded. For example, each individual
wellbore can make a contribution that is Jess than the predetermined field
25 threshold Thfield, while the combined is greater than the predetermined field
threshold Thfield
Then the procedure 1 00 can proceed to step 120 where the nonnegligible
solutions can be returned. The solutions returned can include, for
example, the vector parameter riand/or the vector parameter 4 for each
30 wellbore making a non-negligible contribution. In some embodiments,
parameters such as the cunent magnitude, azimuth angle and the orientation of
the wellbores can be measured or determined from the selected parameter set
- 17-
5
by the data processing unit 64, and these parameters can be retumed as
solutions. In some exemplary embodiments, the solutions can be returned to
the visualizing unit 60 for evaluation by a user, or to any other component of
system 50.
Refening now to FIG. 58, and with continued reference to FIGS. 2 and
4, an exemplary embodiment of an operational procedure 200 for forming a
wellbore in a geologic formation "G" is described. The procedure 200 begins
at step 202 where, a first well bore 12 is identified extending along a first path.
The first well bore 12 can be an existing well bore identified in a crowded field,
10 or the first well bore 12 can be drilled using any drilling method recognized in
the art. A first electrical current letft can then be induced in the first well bore
and a second current Ieffzcan be induced in the second wellbore 14 (step 204).
In some embodiments, the tirst and second electrical cunents letft and letfz
can be excited remotely, e.g., with transmitters 52 of ranging tool 26. Thus,
15 the second current letfz can be excited in the second wellbore 14 without
expressly identifying the location or verifying the existence of the second
wellbore 14. In other embodiments, the first and second cunents lefft and
Ieffz can be directly excited by current source 32 (FIG. 1) at the surface
location "S." In one or more embodiments, the first and second cunents Iefft
20 and Ieffz can be excited at a different point within procedure 200, and the first
and second currents letft and letfz can be maintained continuously or
continually throughout the procedure 200.
At step 206, a third path can be defined having a predetetmined
relationship to the first path is defined. In one or more exemplary
25 embodiments, the third path can be generally parallel to the first path, e.g.,
when the first and third wellbores comprise an SAGD patr. In other
embodiments, the predetermined relationship can be an intersecting
relationship where the third wellbore intersects the first wellbore at a
predetermined or true depth, a lateral branching relationship where the third
30 wellbore branches from the first wellbore at a predetermined location. A
number of well bores N";pe nearby at least a portion of the third path can be
- 18-
estimated to determine a sufficient number of receivers N.,,. for locating the
estimated number of nearby wellbores N'ipe. The sufficient number of
receivers can be determined, e.g., from equations (7) and (9) above, and in
some embodiments is at least five (5) times the estimated number of nearby
5 well bores N'1
P'. A ranging tool 26 including the sufficient number of receivers
54 can be provided in a drill string 18 (FIG. 1 A).
Next in step 208, the drill string 18 can be employed to begin drilling
the third wellbore 16 along the third path. When the ranging tool 26 is
disposed at a first operational position within the third wellbore 16, the
10 received magnetic field Jireccan be detected with the receivers 54, and the
~ received magnetic field H'eccan be communicated to the data processing unit
64 (step 210).
Next, at step 212, the data processing unit 64 can perform procedure
100 (FIG. SA) to determine a number of well bores N"1
P' contributing to the
15 received magnetic field Jirec at the first operational position. The data
processing unit 64 can thereby determine the location of at least the first
wellbore 12with respect to the third wellbore 16. The location of the first
wellbore 12 is returned, and can be used to adjust a direction of drilling to
maintain the path of the third well bore 16 in the predetermined relationship
20 with the first path of the first wellbore 12 (step 214).
Next the procedure 200 returns to step 210 where the ranging tool 26
can again receive a received magnetic field J1rec from a second operational
position along the third path. The procedure 200 can repeat steps 210 through
214 until the third wellbore 16 is complete, and close tolerances can be
25 maintained even when the number of well bores N'1
P' making a non-negligible
contribution to the received magnetic field changes along the third path.
Referring now to FIGS. 6 through 9B, one example of a
mathematically simulated a two-wellbore system 300 is illustrated. A first
wellbore 302 (Pipe 1) and a second well bore 304 (Pipe 2) are simulated in a
30 common plane designated by axes x and y. Currents I1 and h are simulated in
generally opposite directions along the first and second paths defined by the
- 19-
5
first and second wellbores 302, 304 as illustrated by arrows 306 and 308. The
simulated currents I 1 and I2 each have a magnitude l Amp. A third path 310 is
also illustrated between the first and second wellbores 302, 304 along which
ranging tool 26 (FIG. 7) is moved.
As illustrated in FIG. 7, the ranging tool 26 is simulated as including 4
tri-axial receivers 312a, 312b, 312c and 312d disposed symmetrically around
reference point "P ." The tri-axial receivers 312a, 312c are separated along the
y-axis by 20ft., and the tri-axial receivers 312b, 312d are separated along the
x-axis by 20 ft. The reference point "P" at the center of the tri-axial receivers
10 312a, 312b, 312c and 312d was simulated to move along the third path 310
illustrated in FIG. 6.
At a plurality of operational locations along the third path 310, a
forward model magnetic field1f!orwas calculated induced by the first and
second currents I1 and I2for each of the receivers 312a, 312b, 312c and 312d.
15 To simulate a received magnetic field j[rec, a one percent 1% multiplicative
enor with uniform distribution was added to the calculated forward model
magnetic field jffor for each of the receivers 312a, 312b, 312c and 312d at each
of the operational locations along the third path 310. Once the received
magnetic field j[rec was simulated, the system of equations illustrated by
20 equations (2) through (5) were solved as described above with reference of to
step 108 of procedure I 00 (FIG. SA). Since the number of simulated
wellbores was known, the variable N'ipe was defined as two (2), and the
iterative process of steps 110, 112, and 114 were not necessary for
determining the number of nearby wellbores.
25 The parameter set satisfying min{ll1frec- jftorll} for an N"ipe of two
(2) wellbores was determined and the locations of the first and second
wellbores 302, 304 were extracted therefrom for each of the operational
locations. The extracted locations are plotted in FIG. 8 along the simulated
first and second paths for the first and second wellbores 302, 304. The
30 extracted locations for the first well bore 302 are illustrated as asterisks and the
extracted locations for the second wellbore 304 are illustrated as diamonds.
- 20-
As illustrated in FIG. 8, the extracted locations are more accurate where the
third path 310 of the ranging tool 26 (is relatively close to the first and second
wcllbores 302, 304 (toward the right of the graph). In this example, the
accuracy is particularly high where the ranging tool 26 is closer than a radial
5 distance "R" of about 61 meters (about 200 feet). This range is relatively
important for well avoidance and intersection purposes.
As illustrated in FIGS. 9A and 9B, currents were also extracted from
the parameter set found to satisfy min{jjflrec- fltorll}. Again, in FIGS. 9A
and 9B, the x-axis represents the position of the respective wellbores along the
10 x-axis direction. The y-axis represents the magnitude of the extracted
cuncnts. The current magnitudes illustrated are closest to the I Amp
magnitude of the first and second cunents It and h (FIG. 6) where the ranging
tool 26 is simulated to be closest to the simulated wellbores (toward the right
of the graphs). Again, the accuracy is illustrated to be relatively high in a
15 range where accuracy is relatively impmtant for well avoidance and well
intersection purposes.
In one aspect of the disclosure, a method of locating multiple well bores
includes (a) exciting a first electrical current in a first wellbore, (b) exciting a
second electrical current in a second wellbore, (c) disposing a ranging tool at a
20 remote location with respect to the first and second well bores, (d) receiving
and detecting a magnetic field at the remote location with receivers provided
on the ranging tool, and (e) measuring at least one wellbore parameter of each
of the tirst well bore and the second well bore from the magnetic field received
by the ranging tool.
25 In some exemplary embodiments, the at least one wellbore parameter
includes at least one of the group consisting of the first electrical cunent, the
second electrical CU!Tent, a distance of either of the first and second well bores
ti·om the receivers, azimuth angle of either of the tirst and second well bores,
and an orientation of first and second wellbores. The at least one wellbore
30 parameter can include a magnitude of least one of the first current and the
second current.
- 21-
In one or more exemplary embodiments, the method further includes
determining that the received magnetic field is greater than a predetetmined
field threshold. The method may also include calculating a contribution of
each of the first and second to well bores to the received magnetic field, and
5 determining that the contribution of at least one of the first and second
well bores is greater than the predetermined field threshold.
In some exemplary embodiments, the method further includes
determining from the received magnetic field a number of wellbores
contributing to the received magnetic field. The method may also include
10 determining from the received magnetic field that the number of wellbores
contributing to the magnetic field received by the ranging tool is greater than
two and measuring from the received magnetic field at least one wellbore
parameter of at least one well bore other than the first well bore and the second
wellbore. The method can include detennining that the contribution of the at
15 least one well bore other than the first wellbore and the second wellbore to the
received magnetic field is greater than a predetermined threshold value.
In some exemplary embodiments, determining the number ofwellbores
contributing to the magnetic field may include (a) estimating the number of
well bores to define an estimated number of well bores, (b) calculating at least
20 one parameter set for the estimated number of well bores which would produce
the received magnetic field, (c) determining a forward model magnetic field
for each parameter set calculated for the estimated number of well bores, (d)
selecting the parameter set of the at least one parameter set for which a
difference between the received magnetic field and the forward model
25 magnetic field is the least, and (e) detem1ining that the difference between the
received magnetic field and forward model magnetic field for the selected
parameter set is less than a predetermined misfit threshold.
In one or more embodiments, the method may further include
detctmining that the difference between the received magnetic field and
30 forward model magnetic field is not less than the predetetmined misfit
threshold and incrementally increasing the estimated number of wellbores.
The method may also include determining that the incrementally increased
- 22-
estimated number of wellbores is not greater than a max1mum number of
well bores, wherein the maximum number of well bores is based on a number
of receivers provided on the ranging tool. In some exemplary embodiments
the method 11trther includes determining that a magnitude of the received
5 magnetic field is greater than a predetermined field threshold, wherein the
field threshold is selected based on an accuracy of the receivers in detecting a
magnetic field strength. The method may include selecting the predetermined
misfit threshold based on prope1ties of the ranging tool and accuracy
requirements for the measurement of the at least one wellbore parameter of
10 each of the first well bore and the second well bore.
In some exemplary embodiments, disposing the ranging tool at a
remote location includes deploying the ranging tool on a drill string within a
third wellbore, wherein measuring at least one wellbore parameter comprises
measuring a distance of at least one of the first and second well bores from the
15 receivers, and wherein the method fmiher comprises directionally drilling the
third wellbore in a predetermined relationship with respect to at least one of
the first and second wellbores. The predetermined relationship may include at
least one of a parallel relationship, a non-intersecting relationship, an
intersecting relationship, and a laterally branching relationship.
20 In some exemplary embodiments, the first and second currents are
excited at the same fi·equency, and the received magnetic field is received by
an array of single axis magnetometers located in a third wellbore. In some
embodiments, the aJTay of single axis magnetometers may include eight (8)
magnetometers, and the eight (8) magnetometers may be staggered along an
25 axis of the ranging tool. In other exemplary embodiments, an anay of single
axis magnetometers is provided for receiving the received magnetic field,
where the number of single axis magnetometers in the array is at least two (2)
less than three times an estimated number of nearby well bores (i.e., w·ec'?.fYPipe
-2)at the remote location with receivers provided on the ranging tool.
30 In some exemplary embodiments, the first and second wellbores are an
injector and producer respectively of an SAGD pair. In some embodiments,
the first wellbore is a producer of a first SAGD pair, and the second well bore
- 23-
is a producer of a second SAGD pmr. In some embodiments, the first
wellbore is an injector of a first SAGD pair and the second wellbore is a
producer of a second SAGD pair. In some embodiments, the first well bore is
an injector of a first SAGD pair and the second wellbore is an injector of a
5 second SAGD pair. In some embodiments, the first wellbore is a producer of
an SAGD pair, and the second wellbore is a lateral wellbore branching from
the first well bore.
According to another aspect of the disclosure a method of forming a
well bore in a geologic formation includes (a) identifying a first wellbore in the
10 geologic formation along a first path, (b) exciting a first electrical current
along the first path in the first well bore and a second electrical current along a
second path in a second wellbore, (c) drilling a third well bore along a third
path having a predetermined relationship to the first path, (d) detecting a
received magnetic field in the third well bore, ( e )dete1mining from the received
15 magnetic field a number of wellbores contributing to the received magnetic
field, (f) determining a location of the first wellbore based on the number of
well bores determined to be contributing to the received magnetic field, and(g)
adjusting a direction of drilling of the second wellbore to maintain the third
path in the predetermined relationship to the first path.
20 In one or more exemplary embodiments, determining the number of
wellbores contributing to the magnetic field includes (a) estimating the
number of wellbores to. define an estimated number of wellbores, (b)
calculating at least one parameter set for the estimated number of wellbores
which would produce the received magnetic field, (c) detennining a forward
25 model magnetic field for each parameter set calculated for the estimated
number of wellbores, (d) selecting the parameter set of the at least one
parameter set for which a difference between the received magnetic field and
the forward model magnetic field is the least, and (e) determining that the
diflerence between the received magnetic field and loiwm·d model magnetic
30 field for the selected parameter set is less than a predetermined misfit
threshold. In some embodiments, the determined location of the first wellbore
is a parameter in the selected parameter set.
- 24-
In some exemplary embodiments, the method further includes
estimating the number of wellbores to be determined from the received
magnetic field and deploying a ranging tool having Nrec single axis receivers
where N·cc is at least five times greater than an the estimated number of
5 well bores. In some exemplary embodiments, the predetermined relationship is
a generally parallel relationship wherein one of the first and third well bores is
shallower than the other of the first and third well bores such that the first and
second wellbores together define an SAGD pair.
In another aspect of the disclosure, a system for locating multiple
10 wcllbores include (a) a non-transitory memory having a set of instructions
thereon, wherein the instructions include instructions for accepting a received
magnetic field as input, instructions for detem1ining from the received
magnetic field a number of well bores contributing to the received magnetic
field and instructions for detetmining at least one parameter of each well bore
15 detetmined to be contributing to the received magnetic field; and a processor
for executing the set instructions.
In some exemplary embodiments, the instructions for detetmining the
number of well bores contributing to the received magnetic field may include
instructions for (a) estimating the number of wellbores contributing to the
20 received magnetic field to define an estimated number of wellbores, (b)
calculating at least one parameter set for the estimated number of well bores
which would produce the received magnetic field, (c) determining a forward
model magnetic field for each parameter set calculated for the estimated
number of well bores, (e) selecting the parameter set of the at least one
25 parameter set for which a difference between the received magnetic field and
the forward model magnetic field is the least, and (f) determining whether the
ditTerence between the received magnetic field and forward model magnetic
field for the selected parameter set is less than a predetermined misfit
threshold.
30 ln one or more exemplary embodiments, the system fmther includes a
drill string m1d ranging tool carried by the drill string. In some embodiments,
the ranging tool may include a receiver operable to detect and measure the
- 25-
received magnetic field, and the ranging tool may be communicatively
coupled to the processor. In some exemplary embodiments, the ranging tool
may further include a transmitter operable to generate an electromagnetic
probe signal that causes current to flow in electrically conductive bodies
5 exterior to the transmitters to thereby generate the received magnetic field.
10
15
Also, in some exemplary embodiments, the system may futiher include a
transmitter deployed independently of the ranging tool into a first well bore of
a SAGO pair of well bores, and the drill string may be deployed into a second
wellbore of the SAGO pair.
Moreover, any of the methods described herein may be embodied
within a system including electronic processing circuitry to implement any of
the methods, or a in a computer-program product including instructions which,
when executed by at least one processor, causes the processor to perform any
of the methods described herein.
The Abstract of the disclosure is solely for providing the United States
Patent and Trademark Office and the public at large with a way by which to
determine quickly from a cursory reading the nature and gist of technical
disclosure, and it represents solely one or more embodiments.
While various embodiments have been illustrated in detail, the
20 disclosure is not limited to the embodiments shown. Modifications and
adaptations of the above embodiments may occur to those skilled in the art.
Such modifications and adaptations are in the spirit and scope of the
disclosure.
- 26-
5
WE CLAIM:
1. A method of locating multiple well bores, comprising:
exciting a first electrical cutTent in a first well bore;
exciting a second electrical current in a second well bore;
disposing a ranging tool at a remote location with respect to the first
and second well bores;
receiving and detecting a magnetic field at the remote location with
receivers provided on the ranging tool; and
measuring at least one well bore parameter of each of the tirst well bore
10 and the second wellbore from the magnetic field received by the ranging tool.
2. The method of claim 1, wherein the at least one well bore parameter
comptises at least one of the group consisting of the first electrical current, the
second electrical cul1'cnt, a distance of either of the first and second well bores
from the receivers, azimuth angle of either of the first and second well bores,
15 and an orientation of first and second well bores.
3. The method of claim 2, wherein the at least one wellbore parameter
comprises at least one of the first cul1'ent and the second current.
4. The method of claim 1, further comprising determining that the
received magnetic field is greater than a predetermined field threshold.
20 5. The method of claim 4, further comprising:
calculating a contribution of each of the first and second to well bores
to the received magnetic field; and
determining that the contribution of at least one of the first and second
well bores is greater than the predetermined field threshold.
- 27-
6. The method of claim I, further comprising determining from the
received magnetic field a number of wellbores contributing to the received
magnetic field.
7. The method of claim 6, wherein detennining the number of well bores
5 contributing to the magnetic tleld comprises:
estimating the number of well bores to define an estimated number of
well bores;
calculating at least one parameter set for the estimated number of
well bores which would produce the received magnetic field;
10 determining a forward model magnetic tield for each parameter set
15
calculated for the estimated number of well bores;
selecting the parameter set of the at least one parameter set for which a
difference between the received magnetic field and the forward model
magnetic field is the least; and
determining that the difference between the received magnetic field
and forward model magnetic field for the selected parameter set is less than a
predetermined misfit threshold.
8. The method of claim 7, fmiher comprising:
dete1mining that the difference between the received magnetic field
20 and forward model magnetic tleld is not less than the predetermined mistit
threshold; and
incrementally increasing the estimated number of well bores.
9. The method of claim 8, further compnsmg determining that the
incrementally increased estimated number of wellbores is not greater than a
25 maximum number of well bores, wherein the maximum number of well bores is
based on a number of receivers provided on the ranging tool.
- 28-
5
10. The method of claim 7, further compnsmg detem1ining that a
magnitude of the received magnetic field is greater than a predetennined tield
threshold, wherein the predetermined field threshold is selected based on an
accuracy of the receivers in detecting a magnetic field strength.
11. The method of claim 7, further comprising selecting the predetermined
mistit threshold based on properties of the ranging tool and accuracy
requirements for the measurement of the at least one wellbore parameter of
each of the tirst wellbore and the second wellbore.
12. The method of claim 1, wherein disposing the ranging tool at a remote
10 location comprises deploying the ranging tool on a drill string within a third
wellbore, wherein measuring at least one wellbore parameter comprises
measuring a distance of at least one of the first and second well bores from the
receivers, and wherein the method further comprises directionally drilling the
third wellbore in a predetermined relationship with respect to at least one of
15 the first and second well bores.
13. The method of claim 12, wherein the predetermined relationship
includes at least one of a parallel relationship, a non-intersecting relationship,
an intersecting relationship, and a laterally branching relationship.
14. A method of fmming a wellbore in a geologic fommtion, the method
20 comprising:
25
identifying a first well bore in the geologic formation along a first path;
exciting a first electrical current along the tirst path in the first
wellbore and a second electrical cull'ent along a second path in a second
well bore;
drilling a third wellbore along a third path having a predetermined
relationship to the first path;
detecting a received magnetic field in the third wellbore;
- 29-
5
determining from the received magnetic field a number of wellbores
contributing to the received magnetic field;
determining a location of the first wellbore based on the number of
well bores detem1ined to be contributing to the received magnetic field; and
adjusting a direction of drilling of the second well bore to maintain the
third path in the predetermined relationship to the first path.
15. The method of claim 14, wherein determining the number ofwellbores
contributing to the magnetic field comprises:
estimating the number of well bores to define an estimated number of
10 wellbores;
15
calculating at least one parameter set for the estimated number of
well bores which would produce the received magnetic field;
determining a forward model magnetic field for each parameter set
calculated for the estimated number of well bores;
selecting the parameter set of the at least one parameter set for which a
difference between the received magnetic field and the forward model
magnetic field is the least; and
determining that the difference between the received magnetic field
and forward model magnetic field for the selected parameter set is less than a
20 predetermined misfit threshold.
16. The method of claim 15, wherein the determined location of the first
well bore is a parameter in the selected parameter set.
17. The method of claim 14, further comprising:
estimating the number of well bores to be determined from the received
25 magnetic field; and
deploying a ranging tool having N""" single axis receivers where N·ec is
at least five times greater than an the estimated number ofwellbores.
- 30-
5
18. The method of claim 14, wherein the predetermined relationship is a
generally parallel relationship wherein one of the first and third well bores is
shallower than the other of the first and third wellbores such that the first and
second well bores together define a SAGD pair.
19. A system for locating multiple well bores, comprising:
a non-transitory memory having a set of instructions thereon, the
instructions including instructions for accepting a received magnetic field as
input, instructions for determining fi·om the received magnetic field a number
of wellbores contributing to the received magnetic field and instructions for
10 determining at least one parameter of each wellbore determined to be
contributing to the received magnetic field; and
a processor for executing the set instructions.
20. The system of claim 19, wherein the set of instructions for determining
the number of well bores contributing to the received magnetic field includes
15 instructions for:
20
estimating the number of wellbores contributing to the received
magnetic field to define an estimated number of well bores;
calculating at least one parameter set for the estimated number of
well bores which would produce the received magnetic field;
dete1mining a forward model magnetic field for each parameter set
calculated for the estimated number ofwellbores;
selecting the parameter set of the at least one parameter set for which a
difference between the received magnetic field and the forward model
magnetic field is the least; and
25 determining whether the difference between the received magnetic
field and forward model magnetic field for the selected parameter set is less
than a predetermined misfit threshold.
- 31-
21. The system of claim 19, further comprising a drill string and ranging
tool carried by the drill string, wherein ranging tool comprises a receiver
operable to detect and measure the received magnetic field, and wherein the
ranging tool is communicatively coupled to the processor.
5 22. The system of claim 21, wherein the ranging tool further comprises a
transmitter operable to generate an electromagnetic probe signal that causes
current to tlow in electrically conductive bodies exterior to the transmitters to
thereby generate the received magnetic field.
23. The system of claim 21, further comprising a transmitter deployed
10 independently of the ranging tool into a first wellbore of a SAGD pair of
wellbores, and wherein the drill string is deployed into a second wellbore of
the SAGD pair.