EP2021835A2 - Methode d`analyse de formation souterraine utilisant des signaux de reponse transitoires dependants du temps - Google Patents

Methode d`analyse de formation souterraine utilisant des signaux de reponse transitoires dependants du temps

Info

Publication number
EP2021835A2
EP2021835A2 EP07783066A EP07783066A EP2021835A2 EP 2021835 A2 EP2021835 A2 EP 2021835A2 EP 07783066 A EP07783066 A EP 07783066A EP 07783066 A EP07783066 A EP 07783066A EP 2021835 A2 EP2021835 A2 EP 2021835A2
Authority
EP
European Patent Office
Prior art keywords
formation
time
tool
conductivity
electromagnetic
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP07783066A
Other languages
German (de)
English (en)
Inventor
Teruhiko Hagiwara
Erik Jan Banning-Geertsma
Richard Martin Ostermeier
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell Internationale Research Maatschappij BV
Original Assignee
Shell Internationale Research Maatschappij BV
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Shell Internationale Research Maatschappij BV filed Critical Shell Internationale Research Maatschappij BV
Publication of EP2021835A2 publication Critical patent/EP2021835A2/fr
Withdrawn legal-status Critical Current

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/26—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device
    • G01V3/28—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device using induction coils

Definitions

  • the present invention relates to a method of analyzing a subterranean formation traversed by a wellbore.
  • the invention relates to a method of producing a mineral hydrocarbon fluid from an earth formation.
  • the invention relates to a computer readable medium storing computer readable instructions that analyze one or more electromagnetic response signals.
  • Look-Ahead logging comprises detecting an anomaly at a distance ahead of a drill bit.
  • Some look-ahead examples include predicting an over-pressured zone in advance, or detecting a fault in front of the drill bit in horizontal wells, or profiling a massive salt structure ahead of the drill bit.
  • US 2006/0038571 shows that transient electromagnetic responses can be analyzed to determine conductivity values of a homogeneous earth formation (single layer), and of two or three or more earth layers, as well as distances from the tool to the interfaces between the earth layers.
  • the electromagnetic properties of a formation layer comprising a number of thin layers may be approximated by one formation layer comprising an electromagnetic anisotropy. It is thereby avoided to have to take into account each thin layer individually when inverting the responses.
  • anisotropy information is useful in precisely locating mineral hydrocarbon fluid containing reservoirs, as such reservoirs are often associated with electromagnetic anisotropy of formation layers.
  • Said method of analyzing a subterranean formation may be used in a geo- steering application wherein a geo-steering cue may be derived from the one or more time- dependent transient response signals, taking into account electromagnetic anisotropy, and wherein a drilling operation may be continued in accordance with the derived geo-steering cue in order to accurately place a well.
  • a method of producing a mineral hydrocarbon fluid from an earth formation comprising steps of: suspending a drill string in the earth formation, the drill string comprising at least a drill bit and measurement sub comprising a transmitter antenna and a receiver antenna; drilling a well bore in the earth formation; inducing an electromagnetic field in the earth formation employing the transmitter antenna; detecting a transient electromagnetic response signal from the electromagnetic field, employing the receiver antenna; deriving a geosteering cue from the electromagnetic response; continue drilling the well bore in accordance with the geosteering cue until a reservoir containing the hydrocarbon fluid is reached; producing the hydrocarbon fluid.
  • the invention provides a computer readable medium storing computer readable instructions that analyze one or more detected time-dependent transient electromagnetic response signals that have been detected by a tool suspended inside a wellbore traversing a subterranean formation after inducing one or more electromagnetic fields in the formation, wherein the computer readable instructions take into account electromagnetic anisotropy of at least one formation layer in the subterranean formation.
  • FIG. IA is a block diagram showing a system implementing embodiments of the invention.
  • FIG. IB schematically illustrates an alternative system implementing embodiments of the invention
  • FIG. 2 is a flow chart illustrating a method in accordance with an embodiment of the invention
  • FIG. 3 is a graph illustrating directional angles between tool coordinates and anomaly coordinates
  • FIG. 4A is a graph showing a resistivity anomaly in a tool coordinate system
  • FIG. 4B is a graph showing a resistivity anomaly in an anomaly coordinate system
  • FIG. 5 is a graph illustrating tool rotation within a borehole
  • FIG. 6 schematically shows directional components involving electromagnetic induction tools relative to an electromagnetic induction anomaly
  • FIG. 9 is a graph showing apparent dip ( ⁇ aw (t)) for an arrangement as in FIG. 7;
  • FIG. 10 is a graph showing apparent conductivity ( ⁇ ⁇ pp (t)) calculated from both the coaxial (V zz (t)) and the coplanar (V xx (t)) responses for the same conditions as in FIG. 9;
  • FIG. 14 is a schematic illustration showing a coaxial tool with its tool axis parallel to a layer interface
  • FIG. 15 is a graph showing transient voltage response as a function of t as given by the coaxial tool of FIG. 14 in a two-layer formation at different distances from the bed;
  • FIG. 16 is a graph showing the voltage response data of FIG. 15 in terms of the apparent conductivity ( ⁇ ⁇ pp (t));
  • FIG. 17 is similar to FIG. 16 except that the resistivities of layers 1 and 2 have been interchanged;
  • FIG. 20 graphically shows the same data as FIG. 19 plotted as the ratio of target conductivity over local layer conductivity ⁇ j versus ratio of the late time apparent conductivity (J ⁇ pp (t—> ⁇ ) over local layer conductivity CTJ ;
  • FIG. 21 shows a graph containing apparent conductivity ( ⁇ app (t)) versus time for various combinations of D and L;
  • FIG. 22 graphically shows the relationship between ray-path RP and transition time t c ;
  • FIG. 23 is a schematic illustration showing a coaxial tool approaching or just beyond a bed boundary;
  • FIG. 24 is a graph showing transient voltage response as a function of t as given by the coaxial tool of FIG. 23 at different distances D from the bed;
  • FIG. 25 is a graph showing the voltage response data of FIG. 24 in terms of the apparent conductivity ( ⁇ app (t));
  • FIG. 26 is similar to FIG. 25 except that the resistivities of layers 1 and 2 have been interchanged;
  • FIG. 29 graphically shows distance to anomaly ahead of the tool verses transition time (t c ) as determined from the data of FIG. 25;
  • FIG. 30 schematically shows a coplanar tool approaching or just beyond a bed boundary
  • FIG. 31 is a graph showing transient voltage response data in terms of the apparent conductivity (o app (t)) as a function of t as provided by the coplanar tool of FIG. 30 at different distances D from the bed;
  • FIG. 33 graphically shows the same data as FIG. 32 plotted as the ratio of target conductivity ⁇ ? over local layer conductivity ⁇ j versus ratio of the late time apparent conductivity ⁇ app (t ⁇ ) over local layer conductivity ⁇ y
  • FIG. 34 graphically shows distance to anomaly ahead of the tool verses transition time (tc) as determined from the data of FIG. 31
  • FIG. 35 schematically shows a model of a coaxial tool in a conductive local layer (1 ⁇ m), a very resistive layer (100 ⁇ m), and a further conductive layer (1 ⁇ m);
  • FIG. 36 is a graph showing apparent resistivity response versus time, R a pp(0, for a geometry as given in FIG. 35 for various thicknesses ⁇ of the very resistive layer;
  • FIG. 37 schematically shows a model of a coaxial tool in a resistive local layer (10
  • FIG. 38 is a graph similar to FIG. 36, showing apparent resistivity response Rapp(t) versus time for a geometry as given in FIG. 37 for various thicknesses ⁇ of the conductive layer;
  • FIG. 39 schematically shows a model of a coaxial tool in a conductive local layer
  • FIG. 40 is a graph similar to FIG. 36, showing apparent resistivity response versus time, R a pp(t) > for a geometry as given in FIG. 39 for various thicknesses ⁇ of the separating layer;
  • FIG. 45 shows a graph plotting late time asymptotic value of coaxial apparent conductivity ⁇ z z (t— > ⁇ ) from FIGs. 44 to 44, normalized by ⁇ jj , against a variable representing ⁇ ;
  • FIG. 47 shows an electromagnetic induction tool in a formation layer comprising a package of alternating sets of sub-layers
  • FIG. 48 shows a graph of apparent resistivity in co-axial measurement and co- planar measurement of the geometry as in FIG. 47;
  • FIG. 49 schematically shows directional components of an electromagnetic induction tool relative to an anisotropic anomaly
  • FIG. 50 shows a plot of the apparent conductivity ( ⁇ a pp(z; t)) in both z- and t- coordinates for various distances D;
  • FIG. 51 shows a plot of the apparent conductivity ( ⁇ a pp(z; t)) in both z- and t- coordinates;
  • FIG. 52 schematically shows a model of a structure involving a highly resistive layer (100 ⁇ m) covered by a conductive local layer (1 ⁇ m) which is covered by a resistive layer (10 ⁇ m), whereby a coaxial tool is depicted in the resistive layer;
  • FIG. 53A shows apparent resistivity in both z and t coordinates whereby inflection points are joined using curve fitted lines
  • FIG. 53B shows an image log derived from FIG. 53A
  • FIG. 54A schematically shows a coaxial tool seen as approaching a highly resistive formation at a dip angle of approximately 30 degrees;
  • FIG. 54B shows apparent dip response in both t and z coordinates for z-locations corresponding to those depicted in FIG. 54A.
  • Embodiments of the invention relate to analysis of electromagnetic (EM) induction signals and to a system and method for determining distance and/or direction to an anomaly in a formation from a location within a wellbore.
  • the analysis is sensitive to electromagnetic anomalies, in particular electromagnetic induction anomalies.
  • frequency domain excitation a device transmits a continuous wave of a fixed or mixed frequency and measures responses at the same band of frequencies.
  • time domain excitation a device transmits a square wave signal, triangular wave signal, pulsed signal or pseudo-random binary sequence as a source and measures the broadband earth response. Sudden changes in transmitter current cause transient signals to appear at a receiver caused by induction currents in the formation. The signals that appear at the receiver are called transient responses because the receiver signals start at a first value after a sudden change in transmitter current, and then they decay (or increase) with time to a new constant level at a second value.
  • embodiments of the invention propose a general method to determine a direction from a measurement sub to a resistive or conductive anomaly using transient EM responses.
  • the direction to the anomaly is specified by a dip angle and an azimuth angle.
  • Embodiments of the invention propose to define an apparent dip ( ⁇ a pp(t)) and an apparent azimuth ( ⁇ app (t)) by combinations of multi-axial, e.g. bi-axial or tri-axial, transient measurements.
  • the true direction, in terms of dip and azimuth angles ( ⁇ , ⁇ ) may be determined from the analysis of the apparent direction ( ⁇ app (t), ⁇ app (t) ⁇ ).
  • the apparent direction ( ⁇ app (t), ⁇ app (t) ⁇ ) approaches the true direction ( ⁇ , ⁇ ) as a time (t) increases, if the anomaly has a high thickness as seen from the tool.
  • Time-dependent values for apparent conductivity may be obtained from coaxial and coplanar electromagnetic induction measurements, and can respectively be denoted as ⁇ coaxial0-) an d ⁇ oplanarW- Both read the conductivity in the total present formation around the tool.
  • the ⁇ app (t) and ⁇ app (t) both initially read zero when an apparent conductivity ⁇ coax j a i(t) and ⁇ cop i anar (t) from coaxial and coplanar measurements both read the conductivity of the formation surrounding the tool nearby.
  • the apparent conductivity will be further explained below and can also be used to determine the location of an anomaly in a wellbore.
  • FIGs. IA and IB illustrate systems that may be used to implement the embodiments of the method of the invention.
  • a surface computing unit 10 may be connected with an electromagnetic measurement tool 2 disposed in a wellbore 4.
  • the tool 2 is suspended on a cable 12.
  • the cable 12 may be constructed of any known type of cable for transmitting electrical signals between the tool 2 and the surface computing unit 10.
  • the tool is comprised in a measurement sub 11 and suspended in the wellbore 4 by a drill string 15.
  • the drill string 15 further supports a drill bit 17, and may support a steering system 19.
  • the steering system may be of a known type, including a rotatable steering system or a sliding steering system.
  • the wellbore 4 traverses the earth formation 5 and it is an objective to precisely direct the drill bit 17 into a hydrocarbon fluid containing reservoir 6 to enable producing the hydrocarbon fluid via the wellbore.
  • a reservoir 6 may manifest itself as an electromagnetic anomaly in the formation 5.
  • one or more transmitters 16 and one are more receivers 18 may be provided for transmitting and receiving electromagnetic signals into and from the formation around the wellbore 4.
  • a data acquisition unit 14 may be provided to transmit data to and from the transmitters 16 and receivers 18 to the surface computing unit 10.
  • Each transmitter 16 and/or receiver 18 may comprise a coil, wound around a support structure such as a mandrel.
  • the support structure may comprise a non-conductive section to suppress generation of eddy currents.
  • the non-conductive section may comprise one or more slots, optionally filled with a non-conductive material, or it may be formed out of a non-conductive material such as a composite plastic.
  • the support structure is coated with a layer of a high-magnetic permeable material to form a magnetic shield between the antenna and the support structure.
  • Each transmitter 16 and each receiver 18 may be bi-axial or even tri-axial, and thereby contain components for sending and receiving signals along each of three axes. Accordingly, each transmitter module may contain at least one single or multi-axis antenna and may be a 3 -orthogonal component transmitter. Each receiver may include at least one single or multi-axis electromagnetic receiving component and may be a 3 -orthogonal component receiver.
  • a tool/borehole coordinate system is defined as having x, y, and z axes.
  • the z-axis defines the direction from the transmitter T to the receiver R. It will be assumed hereinafter that the axial direction of the wellbore 4 coincides with the z-axis, whereby the x- and y- axes correspond to two orthogonal directions in a plane normal to the direction from the transmitter T to the receiver R and to the wellbore 4.
  • the data acquisition unit 14 may include a controller for controlling the operation of the tool 2.
  • the data acquisition unit 14 preferably collects data from each transmitter 16 and receiver 18 and provides the data to the surface computing unit 10.
  • the data acquisition unit 14 may comprise an amplifier and/or a digital to analogue converter, to amplify the responses and/or convert to a digital representation of the responses before transmitting to the surface computing unit 10 via cable 12 and/or an optional telemetry unit 13.
  • the surface computing unit 10 may include computer components including a processing unit 30, an operator interface 32, and a tool interface 34.
  • the surface computing unit 10 may also include a memory 40 including relevant coordinate system transformation data and assumptions 42, an optional direction calculation module 44, an optional apparent direction calculation module 46, and an optional distance calculation module 48.
  • the optional direction and apparent direction calculation modules are described in more detail in US patent application publication 2005/0092487 and need not be further described here, other than specifying that these optional modules may take into account formation anisotropy.
  • the surface computing unit 10 may include computer components including a processing unit 30, an operator interface 32, and a tool interface 34.
  • the surface computing unit 10 may also include a memory 40 including relevant coordinate system transformation data and assumptions 42, a direction calculation module 44, an apparent direction calculation module 46, and a distance calculation module 48.
  • the surface computing unit 10 may further include a bus 50 that couples various system components including the system memory 40 to the processing unit 30.
  • the computing system environment 10 is only one example of a suitable computing environment and is not intended to suggest any limitation as to the scope of use or functionality of the invention.
  • the computing system 10 is described as a computing unit located on a surface, it may optionally be located below the surface, incorporated in the tool, positioned at a remote location, or positioned at any other convenient location.
  • the memory 40 preferably stores one or more of modules 48, 44 and 46, which may be described as program modules containing computer-executable instructions, executable by the surface computing unit 10.
  • Each module may comprise or make use of a computer readable medium that stores computer readable instructions for analyzing one or more detected time-dependent transient electromagnetic response signals that have been detected by a tool suspended inside a wellbore traversing a subterranean formation after inducing one or more electromagnetic fields in the formation.
  • the instructions may implement any part of the disclosure that follows herein below.
  • the program module 44 may contain computer executable instructions to calculate a direction to an anomaly within a wellbore.
  • the program module 48 may contain computer executable instructions to calculate a distance to an anomaly or a thickness of the anomaly.
  • the stored data 42 may include data pertaining to the tool coordinate system and the anomaly coordinate system and other data for use by the program modules 44, 46, and 48.
  • the computer readable instructions take into account electromagnetic anisotropy of at least one formation layer in the subterranean formation.
  • FIG. 2 is a flow chart illustrating the procedures involved in a method embodying the invention.
  • the illustrate procedures may start at S.
  • procedure “Transmit Signals” (A) the transmitters 16 transmit electromagnetic signals.
  • procedure “Receive Responses” (B) the receivers 18 receive transient responses.
  • procedure “Process Responses” (C) the system processes the transient responses.
  • the procedures may then end at E and/or start again at S.
  • Procedure C may comprise determining a distance and/or a direction to the anomaly may be determined.
  • Procedure C may comprise creating an image of formation features based on the transient electromagnetic responses. Electromagnetic anisotropy of at least one of the formation layers may be taken into account.
  • FIGs. 3-6 illustrate the technique for implementing procedure C for determining distance and/or direction to the anomaly.
  • FIGs. 6 and 41 to 49 illustrate how electromagnetic anisotropy may be taken into account, e.g. in determining distance and/or direction to the anomaly.
  • Each transmitter may comprise a magnetic dipole source, [M x , M y , M z ], in any direction.
  • the formation near the tool is seen as a homogeneous formation.
  • the method may assume that the formation is isotropic. Only three non-zero transient responses exist in a homogeneous isotropic formation. These include the coaxial response and two coplanar responses.
  • Coaxial response V zz (t) is the response when both the transmitter and the receiver are oriented in the common tool axis direction.
  • Coplanar responses, V xx (t) and V ⁇ (t) are the responses when both the transmitter T and the receiver R are aligned parallel to each other but their orientation is perpendicular to the tool axis. All of the cross-component responses are identically zero in a homogeneous isotropic formation.
  • Cross-component responses are either from a longitudinally oriented receiver with a transverse transmitter, or vise versa. Another cross-component response is also zero between a mutually orthogonal transverse receiver and transverse transmitter.
  • the magnetic field transient responses may also be examined in the anomaly coordinate system.
  • the magnetic field transient responses at the receivers [R a , R b , R c ] that are oriented in the [a, b, c] axis direction of the anomaly coordinates, respectively, may be noted as
  • Each transmitter may comprise a magnetic dipole source, [M a , M b , M c ], along the orientation a, b, or c.
  • the method assumes that axial symmetry exists with respect to the c-axis that is the direction from the transmitter to the center of the anomaly.
  • the cross-component responses in the anomaly coordinates are identically zero in time-domain measurements.
  • the magnetic field transient responses in the tool coordinates are related to those in the anomaly coordinates by a simple coordinate transformation P(&, ⁇ ) specified by the dip angle ⁇ ⁇ &) and azimuth angle ( ⁇ ).
  • target direction which is defined as the direction of the anomaly from the origin.
  • the tool is in the origin.
  • the transient response measurements in the tool coordinates are constrained and the two directional angles may be determined by combinations of tri-axial responses.
  • Vy x yy Vy Z P(#, ⁇ ) 0 ' aa P(#, ⁇ )
  • the presence of an anomaly is detected much earlier in time in the effective angles than in the apparent conductivity ( ⁇ J app (t)). Even if the resistivity of the anomaly may not be known until ⁇ J app (t) is affected by the anomaly, its presence and the direction can be measured by the apparent angles. With limitation in time measurement, the distant anomaly may not be seen in the change of ⁇ app (t) but is visible in First modeling Example
  • FIG. 6 depicts a simplified modeling example wherein a resistivity anomaly A is depicted in the form of, for example, a massive salt dome in a formation 5.
  • the salt interface 55 may be regarded as a plane interface.
  • FIG. 6 also indicates coaxial 60, coplanar 62, and cross-component (64) measurement arrangements, wherein a transmitter coil and a receiver coil are spaced a distance L apart from each other. It will be understood that in a practical application, separate tools may be employed for each of these arrangements, or a multiple orthogonal tool. For further simplification, it can be assumed that the azimuth direction of the salt face as seen from the tool is known.
  • the remaining unknowns are the first distance D ⁇ to the salt face 55 from the tool, the second distance D2 of the other side of the salt from the tool, the isotropic or anisotropic formation resistivity, and the approach angle (or dip angle) ⁇ as shown in FIG. 6.
  • the electromagnetic properties of the anomaly may be characterized by normal resistivity Rj_ in the direction of the principal axis of the anisotropy (or normal conductivity ⁇ j_), and in-plane resistivity R// (or in-plane conductivity ⁇ //) in any direction within a plane perpendicular to the principal axis.
  • R// ⁇ Rj_ In case of anisotropy, R// ⁇ Rj_.
  • D2 has been assumed much larger than 100 m, such that within the timescale of the calculation (up to 1 sec) any influence from the other side of the salt A is not detectable in the transient response.
  • the anomaly is large and distant compared to the transmitter- receiver spacing L, the effect of the spacing L can be ignored and the transient responses can be approximated with those of the receivers near the transmitter.
  • the effect of the resistivity anomaly A is seen in the calculated transient responses as time increases.
  • they may be converted to apparent dip and/or apparent conductivity.
  • the approach angle ( ⁇ ) may be reflected at any angle in about 10 ⁇ 4 sec.
  • the distance to the salt face can be also determined by the transition time at which ⁇ a pp (t) takes an asymptotic value. Even if the salt face distance (D) is 100 m, it can be identified and its direction can be measured by the apparent dip ⁇ app (t).
  • the method considers the coordinate transformation of transient EM responses between tool-fixed coordinates and anomaly-fixed coordinates.
  • the anomaly is large and far away compared to the transmitter-receiver spacing, one may ignore the effect of spacing and approximate the transient EM responses with those of the receivers near the transmitter.
  • one may assume axial symmetry exists with respect to the c-axis that defines the direction from the transmitter to the anomaly.
  • the cross-component responses in the anomaly-fixed coordinates are identically zero.
  • a general method is provided for determining the direction to the resistivity anomaly using tri-axial transient EM responses.
  • the method defines the apparent dip ⁇ app (t) and the apparent azimuth ⁇ app (t) by combinations of tri-axial transient measurements.
  • the apparent direction ⁇ ⁇ app (t), ⁇ apP (t) ⁇ reads the true direction ⁇ ⁇ , ⁇ at later time.
  • the ⁇ app (t) and ⁇ app (t) both read zero when t is small and the effect of the anomaly is not sensed in the transient responses or the apparent conductivity.
  • the conductivities ( ⁇ 7 coa ⁇ iai(t) and ⁇ J cop ia n a r (t)) from the coaxial and coplanar measurements both indicate the conductivity of the near formation around the tool.
  • Deviation of the apparent direction (f ⁇ app (t), ⁇ apP (t) ⁇ ) from zero identifies the anomaly.
  • the distance to the anomaly is measured by the time when the apparent direction ( ⁇ a pP (t), ⁇ apP (t) ⁇ ) starts to deviate from zero or by the time when the apparent direction ( ⁇ a pP (t), ⁇ apP (t) ⁇ ) starts approaches the true direction ( ⁇ , ⁇ ).
  • the distance can be also measured from the change in the apparent conductivity.
  • the anomaly is identified and measured much earlier in time in the apparent direction than in the apparent conductivity.
  • apparent conductivity can be used as an alternative technique to apparent angles in order to determine the location of an anomaly in a wellbore.
  • the time- dependent apparent conductivity can be defined at each point of a time series at each logging depth.
  • the apparent conductivity at a logging depth z is defined as the conductivity of a homogeneous formation that would generate the same tool response measured at the selected position.
  • transient EM logging transient data are collected at a logging depth or tool location z as a time series of induced voltages in a receiver loop.
  • time dependent apparent conductivity ( ⁇ (r, t)) may be defined at each point of the time series at each logging depth, for a proper range of time intervals depending on the formation conductivity and the tool specifications.
  • V zZ (t) C ( ⁇ ° ⁇ 5/ ) 2 e- 2 8 / 2
  • the time-changing apparent conductivity depends on the voltage response in a coaxial tool (V z z(t)) at each time of measurement as:
  • the time-changing apparent conductivity is defined from the coplanar tool response V x ⁇ (t) at each time of measurement as, (35) C W
  • Li and L 2 are transmitter-receiver spacing of two coaxial tools.
  • time-changing apparent conductivity is defined for a pair of coaxial tools by,
  • ⁇ app (t) ⁇ .
  • the apparent conductivity is similarly defined for a pair of coplanar tools or for a pair of coaxial and coplanar tools.
  • the deviation from a constant (&) at time (t) suggests a conductivity anomaly in the region specified by time (t).
  • apparent conductivity ( ⁇ J apP (t)) may reveal three parameters in relation to a two-layer formation, including:
  • FIG. 14 illustrates a coaxial tool 80 in which both a transmitter coil (T) and a receiver coil (R) are wound around the common tool axis z and spaced a distance L apart.
  • the symbols ⁇ ⁇ and ⁇ 2 inay represent the conductivities of two formation layers.
  • the coaxial tool 80 be placed in a horizontal well 88 traversing formation layer 5 and extending parallel to the layer interface 55.
  • FIG. 16 shows the voltage data of FIG.
  • the apparent conductivity plots reveal a "constant" conductivity at small t, and at large t but having a different value, and a transition time t c that marks the transition between the two "constant" conductivity values and depends on the distance D.
  • the apparent conductivity as t approaches zero can identify the layer conductivity o ⁇ around the tool, while the apparent conductivity as t approaches infinity can be used to determine the conductivity ⁇ 2 of the adjacent layer at a distance.
  • the distance to the bed boundary 55 from the tool 80 can also be measured from the transition time t c observed in the apparent conductivity plots.
  • the tool reads the apparent conductivity ⁇ of the first layer 5 around the tool 80.
  • Conductivity at small values of t is thought to correspond to the conductivity of the local layer 5 where the tool is located in.
  • the signal reaches the receiver directly from the transmitter without interfering with the bed boundary. Namely, the signal is affected only by the conductivity o ⁇ around the tool.
  • the value of 0.4 is believed to correspond to some average between the conductivities of the two layers, because at large values of t, nearly half of the signals come from the formation below the tool and the remaining signals come from above, if the time for the signal to travel the distance between the tool and the bed boundary is small.
  • the apparent conductivity at large values of t is determined by the target layer 2 conductivity, as shown in line 71 in FIG. 19 when CT 1 is fixed at 1 S/m.
  • the late time conductivity may be approximated by the square root average of two-layer conductivities as:
  • the conductivity at large values of t can be used to estimate the conductivity ( ⁇ 2 ) of the adjacent layer when the local conductivity ( ⁇ i) near the tool is known, for instance from the conductivity as t approaches zero as illustrated in HG. 20.
  • Estimation of D The Distance to the electromagnetic anomaly
  • the distance D from the tool to the bed is reflected in the transition time t c .
  • the transition time at which the apparent conductivity ( ⁇ a pp(t)) starts deviating from the local conductivity (o ⁇ ) towards the conductivity at large values of t depends on D and L, as shown in FIG. 21.
  • the transition time (t c ) can be defined as the time at which the ⁇ a pp(t c ) takes a cutoff conductivity ( ⁇ c ).
  • the cutoff conductivity is represented by the arithmetic average between the conductivity as t approaches zero and the conductivity as t approaches infinity.
  • the transition time (t c ) is dictated by the ray path RP:
  • the distance (D) to the anomaly can be estimated from the transition time (t c ), as shown in FIG. 22.
  • the present invention can identify the location of a resistivity anomaly (e.g., a conductive anomaly and a resistive anomaly). Further, resistivity or conductivity can be determined from the coaxial and/or coplanar transient responses. As explained above, the direction to the anomaly can be determined if the cross-component data are also available. To further illustrate the usefulness of these concepts, the foregoing analysis may also be used to detect an anomaly at a distance ahead of the drill bit.
  • a resistivity anomaly e.g., a conductive anomaly and a resistive anomaly
  • resistivity or conductivity can be determined from the coaxial and/or coplanar transient responses.
  • the direction to the anomaly can be determined if the cross-component data are also available.
  • the foregoing analysis may also be used to detect an anomaly at a distance ahead of the drill bit.
  • FIG. 23 shows a coaxial tool 80 with transmitter-receiver spacing L placed in, for example, a vertical well 88 approaching or just beyond an adjacent bed that is a resistivity anomaly.
  • the tool 80 includes both a transmitter coil T and a receiver coil R, which are wound around a common tool axis and are oriented in the tool axis direction.
  • the symbols ⁇ i and (7 2 may represent the conductivities of two formation layers, and D the distance between the tool 80 (e.g. the transition antenna T) and the layer boundary 55.
  • the tool reads close to 0.55 S/m, representing an arithmetic average between the conductivities of the two layers.
  • t — ⁇ GO nearly half of the signals come from the formation below the tool and the other half from above the tool, if the time to travel the distance (O) of the tool to the bed boundary is small.
  • the distance D is reflected in the transition time t c .
  • the late time conductivity is determined solely by the conductivities of the two layers ( ⁇ i and 02) alone. It is not affected by where the tool is located in the two layers.
  • the axial transmitter induces the eddy current parallel to the bed boundary.
  • the axial receiver receives horizontal current nearly equally from both layers. As a result, the late time conductivity must see conductivity of both formations with nearly equal weight.
  • the ⁇ app (t) reaches a nearly constant late time apparent conductivity at later times as L increases.
  • the late time apparent conductivity ( ⁇ app (t ⁇ ⁇ ) is nearly independent of L.
  • the late time conductivity defined at t 1 second, depends on slightly the distance (D).
  • the transition time (t c ) is dictated by the ray-path RP, D minus L/2 that is, half the distance for the EM signal to travel from the transmitter to the bed boundary to the receiver, independently on the resistivity of the two layers.
  • coplanar transient data are equally useful as a look-ahead resistivity logging method.
  • FIG. 30 shows a coplanar tool 80 with transmitter-receiver spacing L placed in a well 88 and approaching (or just beyond) layer boundary 55 of an adjacent bed that is the resistivity anomaly.
  • a transmitter T and a receiver R are oriented perpendicularly to the tool axis z and parallel to each other.
  • the symbols ⁇ > and 0 2 may represent the conductivities of two formation layers.
  • the next model shows a conductive near layer, a very resistive layer, and a further conductive layer.
  • the geological configuration is depicted in FIG. 35, together with a coaxial tool 80 in a relatively conductive formation 82 wherein an anomaly is located in the form of a relatively resistive layer 83.
  • the formation on the other side of layer 83 as seen from tool 80 and identified in FIG. 35 by reference numeral 84, is identical to the formation 82 on the tool side of the layer 83.
  • the method will also work if the formation 84 on the other side of layer 83 would constitute a layer that has different properties from those of the near formation 82.
  • FIG. 36 is a graph showing calculated apparent resistivity response R a pp versus time t for a geometry as given in FIG. 35.
  • the anomaly is formed of a resistive salt bed, having a resistivity of 100 ⁇ m, and that the formation is formed of for instance a brine-saturated formation having a resistivity of 1 ⁇ m.
  • the tool has been modeled as being oriented with its main axis parallel to the first interface 81 between the brine-saturated formation 82, and the distance between the main axis and the first layer 83, D ⁇ , has been taken 10 m.
  • the resistive bed thickness ⁇ has been varied from a fraction of a to 100 meters in thickness.
  • the subsequent decline of R a pp(t) is the response to a conductive formation behind the salt
  • R app (late t) is a function of conductive bed resistivity and salt thickness. If the time measurement is limited to 10 "2 s, the decline of R app (t) may not be detected for the salt thicker than 500 m.
  • the coaxial responds to a thin (l-2m thick) bed.
  • the time at which R app (t) peaks or begins declining depends on the distance to the conductive bed behind the salt.
  • T app (t) when plotted in terms of apparent conductivity (T app (t), the transition time may be used to determine the distance to the boundary beds.
  • the intermediate layer 83 was a more conductive layer than the surrounding formation 82.
  • This conductive bed 83 may be considered representative of, for instance, a shale layer.
  • (more conductive) layer 83 which has a resistivity of 1 ⁇ m.
  • the third layer 84 is beyond the conductive bed 83 and has a resistivity of 10 ⁇ m as does layer 82.
  • the conductive bed 83 was modeled for a range of thicknesses ⁇ varying from fractions of a meter up to an infinite thickness. The apparent resistivity, as calculated, is set forth in FIG. 38.
  • R app (t) The decrease in R app (t), which can be seen in FIG. 38, is attributed to the presence of the shale (conductive) layer and appears as t -> 10 "5 s.
  • the shale response is fully resolved by an infinitely thick conductive layer that approaches 3 ⁇ m.
  • the subsequent rise in R app (t) is in response to the resistive formation 84 beyond the shale layer 83.
  • the transition time is utilized to determine the distance D2 from the tool 80 to the interface 85 between the second and third layers (83 respectively 84).
  • R app (late t) is a function of conductive bed resistivity. As the conductive bed thickness ⁇ increases, the time measurement must likewise be increased (> 10 "2 s) in order to measure the rise of R app (t) for conductive layers thicker than 100 m.
  • FIG. 39 Still another three-layer model is set forth in FIG. 39, wherein the coaxial tool 80 is in a conductive formation 82 (1 ⁇ m), and a highly resistive second layer 84 (100 ⁇ m) as might be found in, for instance, a salt dome. Formation 82 and the second layer 84 are separated by a first layer 83 that has an intermediate resistance (10 ⁇ m). The thickness ⁇ has been varied in the calculations of the apparent resistivity response, as depicted in FIG. 40.
  • the response to the intermediate resistive layer is seen at 10 "4 s, where R app (t) increases. If the first layer 83 is fully resolved by an infinitely thick bed, the apparent resistivity approaches a 2.6 ⁇ m asymptote. As noted in FIG. 40, the R app (t) undergoes a second stage increase in response to the 100 ⁇ m highly resistive second layer 84. Based on the transition time, the distance to the interface is determined to be 110 m. Though complex, the apparent resistivity or apparent conductivity in the above examples delineates the presence of multiple layers.
  • an electromagnetic anomaly may display anisotropic electromagnetic properties. An example is shown in FIG. 6, if R// ⁇ Rj_.
  • Electromagnetic anisotropy may also arise intrinsically in certain types of formations, such as shales, or it may arise as a result of sequences of relatively thin layers.
  • the principal anisotropy direction corresponds to the approach angle ⁇ .
  • This correspondence is mainly for reasons of simplicity in setting forth the embodiments, and need not necessarily be the case in every situation within the scope of the invention.
  • electromagnetic anisotropy of at least one of the formation layers may be taken into account when analyzing time-dependent transient response signals. This may comprise determining one or more anisotropy parameters that characterize the anisotropic electromagnetic properties.
  • anisotropy parameters are anisotropy ratio ⁇ , anisotropic factor ⁇ , conductivity along a principal anisotropy axis ⁇ j_ (or resistivity along the principal anisotropy axis RjJ, conductivity in a plane perpendicular to the principal anisotropy axis ⁇ // (or resistivity in a plane perpendicular to the principal anisotropy axis R//); tool axis angle relative to the principal anisotropy axis.
  • the distance and/or direction to an anomaly may be determined from the time-dependent transient response signals even when the anomaly, and/or a distant formation layer, comprise(s) an electromagnetic anisotropy or when the transmitter and/or receiver antennae are embedded in an anisotropic formation layer.
  • anisotropy may be extended to multiple bedded formations, including those where only a distant formation layer or target anomaly gives anisotropic electromagnetic induction responses
  • the transmitter and receiver antennae displays anisotropic behavior and one or more other, isotropic or anisotropic layers are present at a distance.
  • the distance and direction from the tool to the more distant layers and/or the target anomaly may then be determined, provided that anisotropy is taken into account.
  • the anisotropy has a vertically aligned principal axis, such that the angle between the tool axis z and the principal anisotropy axis corresponds to the dip angle or deviation angle ⁇ .
  • the term horizontal resistivity Rfj may be employed, which generally corresponds to the resistivity in the anisotropy plane perpendicular to the principal anisotropy direction.
  • the term vertical resistivity Ry generally refers to resistivity in the principal anisotropy direction or normal direction.
  • V ⁇ x and V ⁇ v coplanar responses
  • V ⁇ x coplanar response
  • V ⁇ v coplanar response
  • V ⁇ x coplanar response
  • V ⁇ v coplanar response
  • the cross-component response is from a transverse receiver antenna with the longitudinally oriented transmitter antenna, or vise versa.
  • the transverse receiver antenna is directed within the zx-plane. Any cross- component involving either a transmitter or a receiver oriented in the y-axis direction, i.e. V ⁇ x and V X y and V ⁇ z and V ⁇ y are all vanishing.
  • the lines show the voltage response as a function of time t (ranging from 1E-08 sec to lE+00 sec on a logarithmic scale) after a step-wise sudden switching off of the transmitter.
  • FIG. 42 shows the apparent conductivity that has been calculated from the responses as shown in FIG. 41.
  • the same line numbers have been used as in FIG. 41.
  • the late time apparent conductivity is constant for each of the anisotropic factors, indicative of a macroscopically homogeneous formation.
  • the late time apparent conductivity decreases with anisotropic factor as is expected because the vertical conductivity, along the principal axis of the anisotropy, is lower than the horizontal conductivity.
  • FIG. 45 plots the late time asymptotic value of coaxial apparent conductivity
  • anisotropy can be taken into account, for instance by combining co-axial responses with coplanar responses.
  • the precise embodiment depends on which of the parameters are known or estimated.
  • the sum of the co-axial response with the Xx coplanar response is independent from the approach angle. If C and ⁇ jj are known or estimated then the anisotropy ratio a? follows from the late time value of sum Vz 2 + V ⁇ x . If, on the other hand, the approach angle ⁇ is known, C and ⁇ pj don't need to be known because the anisotropy ratio a? may be derived from Eq. (53). If none of the other parameters is known, Eq. (52) may be employed requiring combining co-axial response with two independent co-planar responses.
  • the dip angle is thus reflected accurately by the asymptotic value of the apparent dip.
  • the asymptotic value is reached in approximately 1E-06 sec.
  • FIG. 47 shows an electromagnetic induction tool 80 in a formation layer 110 comprising a sequence or package of alternating sets of sub-layers 112 and 114, set 112 having electromagnetic properties, notably conductivity, that is different from set 114.
  • the tool axis is depicted in the plane of the sub-layers. While each sub-layer in the laminate of thin layers may have isotropic properties such as isotropic conductivity, the combined effect of the sub-layers may be that the formation layer that consists of the sub-layers exhibits an anisotropic electromagnetic induction.
  • the macroscopic resistivity (inverse of conductivity) of the formation layer in a planar direction may be a resultant of all the layer-resistors in parallel while the macroscopic resistivity in a normal direction (i.e. perpendicular to the layers) may be a resultant of all the layer resistors in series.
  • equation form :
  • Line 115 corresponds to apparent resistivity for co-axial measurement geometry while line 116 corresponds to apparent resistivity for co-planar measurement geometry.
  • the apparent resistivity represented by lines 115 and 116 reflect the near-layer resistivity of 1 ⁇ m at short times after the switching off of the transmitter. After a time span of approximately 2E-5 sec, the apparent resistivity starts to increase due to the higher resistivity of 10 ⁇ m in the first adjacent sub-layers 112. So far, the apparent resistivity reflects what was set forth above for formations comprising two or three isotropic formation layers. However, for later times the sub-layers are no longer individually resolved in the responses, in which case apparent resistivity is believed to reflect contributions from the sub-layer where the tool 80 is located, the adjacent layers and next adjacent layers, and so on. Effectively, the transient responses will show the macroscopic anisotropic behavior. In the example of Fig.
  • FIG. 49 The combined, "macroscopic,” anisotropic effect of a sub-layered anomaly, such as is shown in FIG. 49, may also be observed.
  • the anomaly A is formed of a formation layer having a thickness ⁇ comprising a thinly laminated sequence of a first formation material Al and a second formation material A2.
  • FIG. 49 also indicates coaxial 60, coplanar 62, and cross-component 64 measurement arrangements, wherein a transmitter coil T and a receiver coil R are spaced a distance L apart from each other. The distance between the transmitter coil T and the nearest interface 55 between the near formation layer and the anomaly A is indicated by D ⁇ .
  • anisotropy may be extended to multiple bedded formations, including those where only a distant formation layer displays macroscopic electromagnetic induction responses (such as for instance in FIG. 49) or where a local formation layer wherein the transmitter and receiver antennae are located, displays anisotropic behavior but whereby one or more other, isotropic or anisotropic layers are present at a distance.
  • a shale may cap a reservoir of mineral hydrocarbon fluids. It would thus be beneficial to precisely locate a shale during drilling of a well, and drill between for instance 10 m and 100 m below the shale to enable optimal production of the hydrocarbon fluids from the reservoir. This can be done either by traversing the shale or steering below the shale in a deviated well such as a horizontal section.
  • the hydrocarbon containing reservoir may have materialized in the form of a stack of thin sands, which itself may exhibit anisotropic electromagnetic properties. It would be beneficial to identify the presence of such sands and steer the drilling bit into these sands.
  • geosteering may be accomplished by performing the transient electromagnetic analysis while drilling and taking into account formation anisotropy. This may be implemented using the system as schematically depicted in FIG. IA. More generally, geosteering decisions may be taken based on locating any type of electromagnetic anomaly using transient electromagnetic responses. Such geosteering applications allow to more accurately locate hydrocarbon fluid containing reservoirs and to more accurately drill into such reservoirs allowing to produce hydrocarbon fluids from the reservoirs with a minimum of water.
  • a well bore may be drilled with a method comprising the steps of: suspending a drill string in the earth formation, the drill string comprising at least a drill bit and measurement sub comprising a transmitter antenna and a receiver antenna; drilling a well bore in the earth formation; inducing an electromagnetic field in the earth formation employing the transmitter antenna; detecting a transient electromagnetic response from the electromagnetic field, employing the receiver antenna; deriving a geosteering cue from the electromagnetic response. Drilling of the well bore may then be continued in accordance with the geosteering cue until a reservoir containing the hydrocarbon fluid is reached.
  • the well bore may be completed in any conventional way and the mineral hydrocarbon fluid may be produced via the well bore.
  • Geosteering may be based on locating an electromagnetic anomaly in the earth formation by analysing the transient response in accordance with the present specification, and taking a drilling decision based on the location relative to the measurement sub. The location of the anomaly may be expressed in terms of distance and/or direction from the measurement sub to the anomaly.
  • the drill string may comprise a steerable drilling system 19, as shown in FIG. IA.
  • the drilling decision may comprise controlling the direction of drilling, e.g. by utilizing the steering system 19 if provided, and/or establishing the remaining distance to be drilled.
  • the geosteering cue may comprise information reflecting distance between the target ahead of the bit and the bit, and/or direction from the bit to target. Distance and direction from the bit to the target may be calculated from the distance and direction from the tool to the bit, provided that the bit has a known location relative to the electromagnetic measurement tool.
  • Transient electromagnetic induction data may be correlated with the presence of a mineral hydrocarbon fluid containing reservoir, either directly by establishing conductivity values for the reservoir or indirectly by establishing quantitative information on formation layers that typically surround a mineral hydrocarbon fluid containing reservoir.
  • the transient electromagnetic induction data processed in accordance with the above, is used to decide where to drill the well bore and/or what is its preferred path or trajectory. For instance, one may want to stay clear from faults. Instead of that, or in addition to that, it may be desirable to deviate from true vertical drilling and/or to steer into the reservoir at the correct depth.
  • the distance from the measurement sub to an anomaly in the formation may be determined from the time in which one of apparent conductivity and apparent resistivity begins to deviate from the corresponding one of conductivity and resistivity of formation in which the measurement sub is located and/or determining time in which one of apparent dip and apparent azimuth and cross-component response starts to deviate from zero.
  • the distance may also be determined from when one of apparent dip and apparent azimuth reaches an asymptotic value.
  • the electromagnetic anomaly may be located using at least one of time-dependent apparent conductivity, time dependent apparent resistivity, time-dependent dip angle, and time-dependent azimuth angle from the time dependence of the transient response, in accordance with the disclosure elsewhere hereinabove.
  • Apparent conductivity and apparent dip may also be used to create an "image" or representation of the formation features. This is accomplished by collecting transient apparent conductivity data at different positions within the borehole.
  • the apparent conductivity should be constant and equal to the formation conductivity in a homogeneous formation.
  • the deviation from a constant conductivity value at time (t) suggests the presence of a conductivity anomaly in the region specified by time (t).
  • the collected data may be used to create an image of the formation relative to the tool.
  • the z coordinate references the tool depth along the borehole.
  • the ⁇ J app (z; t) plot shows the approaching bed boundary as the tool moves along the borehole.
  • FIG. 51 shows another example.
  • the z-coordinate represents the tool depth along the borehole with the borehole intersecting the layer boundary in this case.
  • the ⁇ a pp(z; t) plot clearly helps to visualize the approaching and crossing the bed boundary as the tool moves along the borehole, for instance during drilling of the borehole.
  • FIG. 52 shows another example.
  • FIG. 52 wherein a 3-layer model is used in conjunction with a coaxial tool having a i m spacing is in two differing positions in the formation.
  • the results are plotted on FIG. 53A, where the apparent resistivity R app (t) is plotted at various points as the coaxial tool 80 approaches the resistive layer (see FIG. 53B).
  • FIG. 53A may be compared to FIG. 53B to discern the formation features.
  • the drop in R app (t) is attributable to the 1 ⁇ m layer 83 and the subsequent increase in R app (t) is attributable to the 100 ⁇ m layer 84.
  • Curves (91, 92, 93) may readily be fitted to the inflection points to identify the responses to the various beds, effectively imaging the formation.
  • Line 91 corresponds to the deflection points caused by the 1 ⁇ m bed 83, line 92 to the salt 84, and line 93 to the deflection points caused by 10 ⁇ m bed 82.
  • the 1 ⁇ m curve may be readily attributable to direct signal pick up between the transmitter and receiver when the tool is located in the 1 ⁇ m bed.
  • the apparent dip ⁇ app (t) may be used to generate an image log.
  • a coaxial tool is seen as approaching a highly resistive formation at a dip angle of approximately 30 degrees.
  • the apparent dip response is shown in FIG. 54B.
  • the time at which the apparent dip response occurs is indicative of the distance to the formation.
  • a curve may be drawn indicative of the response as the tool approaches the bed, as shown in FIG. 54B.
  • the subterranean formation traversed by a wellbore may be imaged using a tool comprising a transmitter for transmitting electromagnetic signals through the formation and a receiver for detecting response signals in a procedure comprising steps wherein
  • the transmitter is energized to propagate an electromagnetic signal into the formation
  • the tool is moved to at least one other position within the wellbore, whereafter the steps set out above are repeated. Optionally, this can be done again. Then an image of the formation within the subterranean formation is created based on the plots of the derived quantity.
  • Optionally tool is then again moved to at least one more other position within the wellbore and the whole procedure can be repeated again.
  • Creating the image of the formation features may include identifying one or more inflection points on each plotted derived quantity and fitting a curve to the one or more inflection points.
  • an image of the formation may be created using apparent conductivity/resistivity and apparent dip angle without the additional processing required for inversion and extraction of information.
  • This information is capable of providing geosteering queues as well as the ability to profile subterranean formations.

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Abstract

L'invention concerne un procédé d'analyse d'une formation souterraine traversée par un puits. Le procédé fait appel à un outil comprenant une antenne émettrice et une antenne réceptrice, la formation souterraine comprenant une ou plusieurs couches. L'outil est suspendu dans le puits, et un ou plusieurs champs électromagnétiques sont induits dans la formation. Un ou plusieurs signaux de réponse transitoire dépendant du temps sont détectés et analysés. Une anisotropie électromagnétique d'au moins une des couches de la formation est détectable. Des repères de géopilotage peuvent être dérivés des signaux de réponse transitoire dépendant du temps, pour le forage continu du puits jusqu'à ce qu'un réservoir d'hydrocarbures soit atteint. Les hydrocarbures peuvent alors être produits.
EP07783066A 2006-05-04 2007-05-02 Methode d`analyse de formation souterraine utilisant des signaux de reponse transitoires dependants du temps Withdrawn EP2021835A2 (fr)

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WO2007131007A2 (fr) 2007-11-15
NO20084967L (no) 2008-11-26
AU2007248114B2 (en) 2010-12-16
WO2007131007A3 (fr) 2008-04-03
US20070256832A1 (en) 2007-11-08
BRPI0711054A2 (pt) 2011-08-23
EA200870499A1 (ru) 2009-04-28
AU2007248114A1 (en) 2007-11-15
CA2651275A1 (fr) 2007-11-15

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