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    • 专利摘要:
    method and apparatus for conducting wellbore logging operations. The present invention relates to an apparatus and method for estimating a parameter of interest of a terrestrial formation (13) which involves alignment information between non-colocated oriented receivers and their non-colocalized oriented transmitters. the method may include generating signal responses indicative of the energy transmitted into the terrestrial formation (13); estimate differences in alignment between transmitters and receivers; use estimated differences in alignment to compensate for misalignment; and estimating a parameter of interest using the offset-compensated signals. the alignment estimate can include an inversion of at least one measurement from an alignment sensor (35). the apparatus may include a downhole assembly (24) with oriented transmitters, oriented receivers, one or more alignment sensors, and at least one processor configured to compensate for misalignment between at least one oriented transmitter (50, 51) and the minus one oriented receiver (60, 61).
    公开号:BR112014021186B1
    申请号:R112014021186-8
    申请日:2013-05-06
    公开日:2021-07-20
    发明作者:Michael B. Rabinovich；Sergey Martakov；Hans-Martin Maurer
    申请人:Baker Hughes Incorporated；
    IPC主号:
    专利说明:

    DESCRIPTION FIELD
    [0001] The present invention refers to the exploration of hydrocarbons involving electrical investigations of a well hole that penetrates a terrestrial formation. BACKGROUND OF THE DESCRIPTION
    [0002] In downhole operations such as drilling, geotargeting and measurement during drilling (MWD) operations, sensor devices are included with a wellbore column that measure various parameters of a formation and/or a wellbore . Such sensor devices are typically arranged to have a desired orientation or alignment, and the resulting measurements are analyzed based on such alignments. In practice, such alignment often cannot be achieved with the desired precision. Misalignment can be caused by different factors such as limited turn positioning accuracy during tool fabrication and/or assembly as well as tool bending while profiling. Navigation through a terrestrial formation can result in sensor devices moving out of a desired alignment, including deformations of the conveyor along which the sensor devices can be positioned. The folding effect can be significant for deep reading azimuth tools with large transmitter-receiver spacings. SUMMARY OF DESCRIPTION
    [0003] In aspects, the present description is related to methods and apparatus that estimate at least one parameter of interest while compensating for differences in alignment between the oriented transmitters and receivers.
    [0004] An embodiment according to the present description includes a method of conducting logging operations within a wellbore that penetrates a terrestrial formation, comprising: estimating at least one parameter of interest of the terrestrial formation using the signals generated by at least a receiver oriented over a downhole assembly in response to energy generated by at least one transmitter oriented over the downhole assembly and information indicative of alignment between the at least one oriented transmitter and the at least one oriented receiver, wherein the at least a oriented receiver includes one of: i) a single oriented receiver and ii) a plurality of colocated oriented receivers, and wherein at least one oriented transmitter includes one of: i) a single oriented transmitter and ii) a plurality of colocated oriented transmitters .
    [0005] Another embodiment according to the present description includes an apparatus for conducting logging operations within a wellbore that penetrates an onshore formation, comprising: a downhole assembly configured to be transported within the wellbore; at least one oriented transmitter disposed on the downhole assembly and configured to transmit energy into the terrestrial formation; at least one oriented receiver disposed on the downhole assembly and configured to receive a signal from the terrestrial formation; at least one alignment sensor disposed on the downhole assembly and configured to receive the alignment information, wherein the at least one oriented receiver includes one of: i) a single oriented receiver and ii) a plurality of co-located oriented receivers, and wherein at least one steered transmitter includes one of: i) a single steered transmitter and ii) a plurality of colocalized steered transmitters; and at least one processor configured to: estimate at least one terrestrial formation parameter of interest using information from signals generated in at least one oriented receiver.
    [0006] Another embodiment in accordance with the present description includes a non-transient computer-readable medium product that has instructions stored therein which, when executed by at least one processor, cause at least one processor to execute a method, the method comprising : estimating at least one parameter of interest of a terrestrial formation using the signals generated by at least one receiver oriented on a downhole set in response to the energy generated by at least one transmitter oriented on the downhole set, and information indicative of alignment between at least one steered transmitter and at least one steered receiver, wherein at least one steered receiver includes one of: i) a single steered receiver and ii) a plurality of co-located steered receivers, and wherein at least one steered receiver oriented includes one of: i) a single oriented transmitter and ii) a plurality of colocated oriented transmitters.
    [0007] Another modality according to the present description includes a method for conducting logging operations within a wellbore that penetrates a terrestrial formation, comprising: estimating at least one parameter of interest of the terrestrial formation using the signals generated by at least a receiver oriented over a downhole assembly in response to energy generated by at least one transmitter oriented over the downhole assembly, and information indicative of alignment between at least one oriented transmitter and at least one oriented receiver, wherein at least at least one oriented receiver includes one of: i) a single oriented receiver and ii) a plurality of oriented receivers not co-located, and wherein at least one oriented transmitter includes one of: i) a single oriented transmitter and ii) a plurality of oriented transmitters non-colonized oriented.
    [0008] Another embodiment according to the invention is an apparatus for conducting logging operations within a wellbore that penetrates an onshore formation, comprising: downhole assembly configured to be transported within the wellbore; at least one oriented transmitter disposed on the downhole assembly and configured to transmit energy into the terrestrial formation; at least one oriented receiver disposed on the downhole assembly and configured to receive signals from the terrestrial formation; at least one alignment sensor disposed on the downhole assembly and configured to receive the alignment information, wherein the at least one oriented receiver includes one of: i) a single oriented receiver and ii) a plurality of oriented receivers not co-located , and wherein the at least one oriented transmitter includes one of: i) a single oriented transmitter and ii) a plurality of non-colocated oriented transmitters; and at least one processor configured to: estimate at least one terrestrial formation parameter of interest using information from signals generated in at least one oriented receiver.
    [0009] Another embodiment in accordance with the present description includes a non-transient computer-readable medium product that has instructions stored therein which, when executed by at least one processor, cause at least one processor to execute a method, the method comprising : estimating at least one parameter of interest of a terrestrial formation using the signals generated by at least one receiver oriented on a downhole set in response to the energy generated by at least one transmitter oriented on the downhole set, and information indicative of alignment between at least one oriented transmitter and at least one oriented receiver, wherein at least one oriented receiver includes one of: i) a single oriented receiver and ii) a plurality of non-colocated oriented receivers, and wherein at least one oriented transmitter includes one of: i) a single oriented transmitter and ii) a plurality of non-local oriented transmitters. ted.
    [00010] Examples of most important features of the description have been summarized quite broadly so that their detailed description that follows can be better understood and so that the contributions they represent to the art can be appreciated. BRIEF DESCRIPTION OF THE DRAWINGS
    [00011] For a detailed understanding of the present description, reference should be made to the following detailed description of the modalities, taken in conjunction with the accompanying drawings, in which like elements have been given like numbers, in which:
    [00012] Fig. 1 shows a schematic of a downhole assembly (BHA) positioned within a wellbore along a drill string according to an embodiment of the present description;
    [00013] Fig. 2 shows a schematic enlargement of an embodiment of a resistivity tool on the BHA with strain sensors and with colocalized transmitters and colocalized receivers configured for positioning within a wellbore according to an embodiment of the present description;
    [00014] Fig. 3 shows a schematic enlargement of another embodiment of a resistivity tool over the BHA with a third transmitter configured for positioning within a wellbore according to an embodiment of the present description;
    [00015] Fig. 4 shows a flowchart of a method for estimating at least one parameter of interest according to an embodiment of the present description;
    [00016] Fig. 5 shows a graph of amplitude vs. distance for boundary curves based on receiver signals before and after compensating for strain;
    [00017] Fig. 6 shows a schematic of a transmitter-receiver combination with the associated magnetic moments according to an embodiment of the present description;
    [00018] Fig. 7 shows a schematic enlargement of another embodiment of a resistivity tool over the BHA with non-colocated transmitters and non-colocated receivers configured for positioning within a wellbore according to an embodiment of the present description; and
    [00019] Fig. 8 shows a flowchart of a method for estimating at least one parameter of interest according to an embodiment of the present description. DETAILED DESCRIPTION
    [00020] This description generally refers to hydrocarbon exploration involving electrical investigations of a wellbore that penetrates a terrestrial formation. These investigations may include estimating at least one parameter of interest in the terrestrial formation and using the additional information to compensate for misalignment between transmitters and receivers, such as due to deformation of a carrier.
    [00021] The present description is susceptible to modalities in different ways. Specific embodiments of the present description are shown in the drawings, and will be described in detail herein, with the understanding that the present description is to be considered an exemplification of the principles of the description, and is not intended to limit the description to what is illustrated and described herein. Indeed, as will be apparent, the teachings of the present description can be used for a variety of well tools and in all phases of well construction and production. Accordingly, the embodiments discussed below are merely illustrative of the applications of the present description.
    [00022] Fig. 1 shows an exemplary embodiment of a well drilling, logging and/or geotargeting system 10 that includes a drill string 11 that is shown disposed within a wellbore or well 12 that penetrates at least one onshore formation 13 during a drilling operation and takes property measurements of formation 13 and/or wellbore 12 at the downhole. As described herein, "wellbore" or "well" refers to a single hole that makes up all or part of a drilled well. As described herein, "formations" refer to the various features and materials that can be found in a subsurface environment and surround the wellbore. The term "information" includes, but is not limited to, raw data, processed data, and signals.
    [00023] In one embodiment, system 10 includes a conventional tower 14 that can support a rotary table 16 that is rotated at a desired rotational speed. The drill string 11 includes one or more sections of drill pipe 18 that extend downwardly into the wellbore 12 of the rotary table 16, and is connected to a drill assembly 20. Drilling fluid or drilling mud 22 is pumped through the drill string 11 and/or the wellbore 12. The well drilling system 10 also includes a downhole assembly (BHA) 24. In one embodiment, a drilling motor or mud motor 26 is coupled to drill assembly 20 and rotates drill assembly 20 as drilling fluid 22 is passed through and around mud motor 26 under pressure.
    [00024] In one embodiment, the drill assembly 20 includes a steering assembly that includes a shaft 28 connected to a drill bit 30. The shaft 28, which in one mode is coupled to the mud motor, is used in operations a geotargeting tool to drive drill bit 30 and drill string 11 through the formation.
    [00025] In one embodiment, the drilling assembly 20 is included in the downhole assembly (BHA) 24, which is available within the system 10 at or near the downhole portion of the drill string 11. The system 10 includes any number of downhole tools 32 for various processes including formation drilling, geotargeting, and formation assessment (FE) to measure versus depth and/or time one or more physical quantities in or around a borehole of well. Tool 32 may be included in or incorporated as a BHA, drill string component or other suitable carrier. A "carrier" as described herein means any device, device component, device combination, medium and/or member that can be used to transport, house, support or otherwise facilitate the use of another device, device combination, medium. and/or member. Exemplary non-limiting carriers include drill strings of the spiral pipe type, the bonded pipe type, and any combination or portion thereof. Other carriers include, but are not limited to, casing tubes, cables, cable rigs, slickline rigs, drop shots, downhole subs, downhole assemblies, and drill strings.
    [00026] In one embodiment, one or more downhole components, such as the drill string 11, the downhole tool 32, the drill assembly 20 and the drill bit 30, include configured sensor devices 34 to measure various parameters of the formation and/or wellbore. For example, one or more parameter 34 sensors (or sensor sets such as MWD subs) are configured for formation evaluation measurements and/or other parameters of interest (referred to herein as "evaluation parameters") relating to formation, wellbore, geophysical characteristics, wellbore fluids and boundary conditions. These sensors 34 may include formation evaluation sensors (e.g., resistivity, dielectric constant, water saturation, porosity, density, and permeability), sensors for measuring wellbore parameters (e.g., wellbore size, slope, and wellbore azimuth, and wellbore roughness), sensors for measuring geophysical parameters (eg acoustic velocity, acoustic displacement time, electrical resistivity) sensors for measuring wellbore fluid parameters (eg viscosity, density, clarity, rheology, pH level, and gas, oil and water content), boundary condition sensors, and sensors for measuring physical and chemical properties of wellbore fluid.
    [00027] System 10 also includes sensors 35 to measure force, operating and/or environmental parameters relating to bending or other static and/or dynamic deformation of one or more downhole components. Sensors 35 are collectively described herein as "strain sensors" and encompass any sensors located on the surface and/or downhole that provide measurements relating to bending or other deformation, static or dynamic, of a downhole component. Examples of deformation include deflection, rotation, tension, twisting and bending. Such sensors 35 provide data that is related to forces on the component (eg, strain sensors, WOB sensors, TOB sensors) and are used to measure a deformation or bending that could result in a change in position, alignment and/ or orientation of one or more sensors 34. In a non-limiting modality, sensors 35 may include one or more of: (i) a strain gauge, (ii) a transmitter oriented at an angle not X, not Z, (iii ) a receiver oriented at a non-X, non-Z angle, (iv) a differential magnetometer, (v) a differential accelerometer, (vi) an optical sensor, and (vii) a fiber optic sensor.
    [00028] For example, a distributed sensor system (DSS) is arranged on the drill string 11 and the BHA 24 includes a plurality of sensors 35. The sensors 35 perform measurements associated with forces on the drill string that can result in deformation , and can thereby result in misalignment of one or more sensors 34. Non-limiting examples of measurements performed by sensors 35 include accelerations, velocities, distances, angles, forces, moments, and pressures. Sensors 35 may also be configured to measure environmental parameters such as temperature and pressure. In a non-limiting example, sensors 35 may be distributed throughout an entire drill string and tool (such as a drill bit) at the far end of drill string 11. In other embodiments, sensors 35 may be configured to measure directional characteristics at various locations along wellbore 12. Examples of such directional characteristics include slope and azimuth, curvature, tension, and bending moment.
    [00029] Fig. 2 shows a downhole component such as a drill pipe section or BHA 24 that includes a plurality of strain sensors 35 incorporated in a drill sensor sub 37 and disposed along a geometric axis of the drill string portion. The BHA 24 has a longitudinal axis 70. This drill sensor sub 37 may include sensors for measuring weight on bit (WOB), torque on bit, annular and internal space pressure, and annular and instrument space temperature. In this example, each of the sensors 35 includes one or more strain gauges 38, 40 and 42 for measuring strain, which can be used to calculate deformation characteristics such as curvature, bending tool face angle, and bending angle. well tool face. Other non-limiting examples of sensors 35 include magnetometers and inclinometers configured to provide tilt data. The use of a plurality of strain sensors 35 is exemplary and illustrative only, as some embodiments of the present description can be realized with a single strain sensor 35.
    [00030] An exemplary orthogonal coordinate system includes a geometric z axis that corresponds to the longitudinal geometric axis of the downhole component, and perpendicular x and y geometric axes. The coordinate system indicates directions to express the deformation of sub 37 within the wellbore. In one embodiment, sensors 35 are configured to make independent perpendicular bending moment measurements at selected cross-sectional locations of tool 32. For example, strain gauges 38 and 40 are configured to make bending moment measurements along the tool. x and geometric axis of the y axis, respectively.
    [00031] Generally, some of the teachings here are reduced to an algorithm that is stored on a non-transient machine-readable medium. The algorithm is implemented by a computer or processor such as surface processing unit 36 or tool 32 and provides operators with a desired output. For example, the electronics in tool 32 can store and process downhole data, or transmit the data in real time to surface processing unit 36 via cable, or any type of telemetry such as mud pulse telemetry or tubes spun during a drilling or drilling operation during measurement (MWD).
    [00032] In one embodiment, parameter sensors 34, strain sensors 35 and/or other downhole components include and/or are configured to communicate with at least one processor to receive, measure and/or estimate directional characteristics or other of the downhole, wellbore and/or formation components. For example, sensors 34, strain sensors 35 and/or BHA 24 are equipped with transmission equipment to communicate with at least one processor, such as a surface processing unit 36 or a downhole processor (not shown). Such transmission equipment can take any desired shape, and different transmission media and connections can be used. Examples of connections include, but are not limited to, wired, fiber optics, acoustics, wireless connections, and mud pulse telemetry.
    [00033] The at least one processor may be configured to receive data and generate information such as a mathematical model to estimate or predict the bending or other deformation of various components. For example, at least one processor may be configured to receive downhole data as well as additional data (eg, from a user or database) such as downhole size and downhole component geometric data such as such as size/shape and component material. In one embodiment, the surface processing unit 36 is configured as a surface drilling control unit which controls various drilling parameters such as rotational speed, weight on bit, drilling fluid flow parameters and others and records and displays real-time training assessment data. Surface processing unit 36, tool 32 and/or other components may also include components as needed to provide storage and/or processing of data collected from various sensors herein. Exemplary components include, without limitation, at least one processor, storage, memory, input devices, output devices, and the like.
    [00034] As the drill string 11 can be folded into a wellbore, transmitters 50, 51 and receivers 60, 61 that are arranged on the BHA 24 or otherwise along the drill string 11 can suffer displacements in alignment at different positions within wellbore 12. Signals received by receivers 60, 61 due to energy emitted by transmitters 50, 51 may change due to a change in alignment of a transmitter-receiver pair (eg transmitter 50- receiver 60). In each pair, the transmitter and receiver can be oriented orthogonal to each other. Transmitters 50, 51 and receivers 60, 61 may each include a directional antenna. Transmitters 50, 51 and/or receivers 60, 61 may be co-located. Here, the term "colocated" refers to two or more transmitters/receivers that use intertwined coils or separate coils in such proximity as to behave like a point transmitter/receiver as understood by one of ordinary skill in the art. Two receiver/transmitter positions can be considered colocalized if the received signals, due to the energy emitted by the transmitter(s), at both positions are substantially identical within the selected measurement accuracy. The non-colocated transmitters/receivers are not intertwined and are separated by a sufficient distance so as to behave as individual transmitters/receivers as understood by one of skill in the art. Thus, two receiver/transmitter positions can be considered not co-located if the received signals, due to the energy emitted by the transmitter(s), in both positions are different within the selected measurement accuracy. In this non-limiting mode, the transmitter 50 can be oriented in the Z direction and the transmitter 51 can be oriented in the X direction. Correspondingly, the receiver 60 can be oriented in the X direction and the receiver 61 can be oriented in the Z direction. a transmitter 50, 51 and a receiver 60, 61 can be estimated based on the deformation of the drill string 11, which can be estimated using one or more deformation sensors 35 disposed on the drill string 11. The deformation sensors 35 may be positioned to provide information indicative of strain along geometric axes relevant to the orientation of transmitters 50, 51 and receivers 60, 61. For example, the strain direction can be estimated using strain sensors 35 distributed around the circumference of sub 37. Although Fig. 2 shows the transmitters oriented 50, 51 and receivers oriented 60, 61 in an alternating ZX pattern, this is exemplary It is illustrative only, and transmitters and receivers can be oriented in any combination of orientation including combinations with a triaxial antenna such as a Z transmitter with an XYZ receiver (not shown). In some embodiments, the oriented transmitters 50, 51 may include coils configured such that the coil(s) of the transmitter 50 and the transmitter 51 are wound around each other and/or spaced in such close proximity to be co-located as it would be understood by someone skilled in the art. Similarly oriented receivers 60, 61 may include coils configured such that the coil(s) of receiver 60 and receiver 61 are wound around each other and/or spaced in such proximity as to be co-located as would be understood by someone versed in the technique. Some modalities can only use a single transmitter and a single receiver.
    [00035] In some embodiments alignment information can be estimated using a hole direction change radius (such as local acute angle) from a measured bending moment. Acute angle severity is a measure of a change toward a wellbore within a given length of the wellbore. Acute angle severity can be stored as a bending moment function. Precalculated values for the bending moment can be stored in a lookup table. Another look-up table may include precalculated values for an angle of misalignment between at least one transmitter 50, 51 and its corresponding receiver 60, 61. The misalignment angle lookup table can show the angle as a function of acute angle severity. For a measured depth in wellbore 12, a local acute angle severity can be obtained from the bending moment measured by at least one strain sensor 35 using the first look-up table. Local misalignment can be obtained from local acute angle severity and using the second look-up table.
    [00036] Fig. 3 shows another modality according to the present description, where a third transmitter 52 (or receiver 62), can be used instead of strain sensors 35. Using the two pairs of oriented transmitters 50, 51 and receivers oriented 60, 61, oriented in the Z and X directions, respectively, a third transmitter 52 (or receiver 62) can be introduced at an angle εt (or εr). In Fig. 3, the angle εt (or εr) is shown in the X-Y plane, however, this is exemplary and illustrative only, since the angle εt (or εr) can be oriented in any direction. In some embodiments, only the third transmitter 52 or only the third receiver 62 can be present.
    [00037] Fig. 4 shows a flowchart of a method 400 according to an embodiment of the present description. At step 410, oriented transmitters 50, 51 and oriented receivers 60, 61 may be transported within wellbore 12 along with one or more strain sensors 35 (Fig. 2) and/or a third transmitter 52 (Fig. 3). Transmitters 50, 51 may be oriented substantially perpendicular to each other. Similarly, receivers 60, 61 may be oriented substantially perpendicular to each other. In this example, the transmitters 50, 51 are oriented in the Z and X directions, and their corresponding receivers 60, 61 are oriented in the X and Z directions. In step 420, energy can be transmitted into the terrestrial formation 13 using the oriented transmitters 50, 51. In step 430, oriented receivers 60, 61 can generate signals indicative of the response of the terrestrial formation to transmitted energy. The generated signals can be indicative of at least one resistivity property of the terrestrial formation. In step 440, a difference in alignment between each of the substantially orthogonally aligned oriented transmitters 50, 51 and receiver 60, 61 can be estimated. In step 450, at least one processor can compensate for the BHA 24 warping effects on the receiver signals using the estimated difference in alignment. In step 460, at least one parameter of interest from the terrestrial formation 13 can be estimated using the receiver signals after compensation.
    [00038] Once the difference in alignment angles is estimated the signals generated by the receivers 60, 61 responsive to the energy emitted by the transmitters 50, 51 can be modified to compensate for the misalignment between the transmitters 50, 51 and the individual receivers 60, 61 .
    [00039] In modalities that use one or more strain sensors 35 (Fig. 2), the compensation for strain of the BHA 24 can include applying a set of algorithms using the estimated differences in alignment. Compensation for deformation may include compensation for misalignment due to an angular displacement between the transmitters and receivers and a displacement (eg, off-axis) between the relative positions of the transmitters and receivers due to the deformation of the BHA 24. The displacement angular can be solved with the following exemplary equations: Amp ZZ measured = Amp ZZ true * cos(Deformation) + Amp ZX true * sin(Deformation)Amp ZX measured = Amp ZZ true * sin(Deformation) + Amp ZX true * cos( Deformation)Amp XZ measured = Amp XZ true * cos(Deformation) + Amp XX true * sin(Deformation)Amp XX measured = Amp XZ true * sin(Deformation) + Amp XX true * cos(Deformation) where, Amp AB is a signal amplitude from transmitter A to receiver B; X stands for cross transmitter/receiver; and Z stands for axial receivers/transmitters.
    [00040] In modalities that use a third transmitter oriented at an angle ε in the XZ plane, compensation for BHA 24 deformation may include applying a set of algorithms using the differences in alignment estimated with the following exemplary equations: Amp Measured RX = Amp ZZ true * sin(Deformation) + Amp ZX true * cos(Deformation)Amp RZ measured = Amp ZZ true * cos(Deformation) + Amp ZX true * sin(Deformation)Amp RT measured = Amp ZZ true * sin(Deformation + ε ) + Amp ZX true * cos(Deformation + ε)where, Amp RB is the amplitude of the signal received at receiver R from transmitter B, X means cross transmitter, Z means axial transmitter, and T means transmitter tilted at an angle εt (or εr). The three measurements (Measured Amp RX, Measured Amp RZ, and Measured Amp RT) can be used to solve for Amp ZZ True, Amp ZX True, and Amp XX True.
    [00041] In the case where a receiver becomes positioned off-axis, the following exemplary equation can be used to compensate:
    where H β,0 is the magnetic field vector about the axis—longitudinal geometric 70, β is the angle of the receiver, Hoff is the magnetic field vector due to the off-axis magnetic position of the receiver, —H i is the vector of magnetic field due to an inhomogeneous part of each formation 13, es is the sensitivity vector of the receiver 60, 61. For small strain angles β and a large distance to—the remote bed (the order case), the field H i created by the inhomogeneous medium can be approximately homogeneous in the antenna within the range of position variation caused by the deformation so that the off-axis component, ie the change in that field due to the receiver's position change, need not be considered.
    [00042] The at least one parameter of interest of the terrestrial formation can be estimated using the "true" amplitudes obtained after compensation for deformation of the BHA 24. The at least one parameter of interest can include, but is not limited to, one or more than: (i) complex conductivity/resistivity (ie, the real and imaginary part), (ii) dielectric constant, (iii) boundary distance, and (iv) remote bed resistivity (ie, the resistivity of a layer behind a limit). In some embodiments, the XZ signal strength and/or the XZ signal tool face direction can also be estimated. In some cases, strain in a section of wellbore 12 can be estimated over a separate logging run from the logging run where signals are generated by receivers 60, 61.
    [00043] Fig. 5 shows a graph with curves that represent the signals generated by the receivers 60, 61 before and after deformation correction. Curve 510 represents the amplitude/limit distance response of multi-component propagation resistivity tool after strain compensation. Curve 520 represents the amplitude/distance after compensating for differences between oriented transmitters and oriented receivers.
    [00044] Fig. 6 shows a schematic of a transmitter-receiver configuration with orientations of the magnetic moments. In some embodiments, folding effects can be seen in measurement of HZX (one or more of the real or imaginary components of HZX), where Z is the orientation of the transmitter 50 substantially parallel to the longitudinal axis 70 and X is the orientation of the receiver 60 substantially perpendicular to tool axis 70. For example, if transmitter 50 is located at point T and receiver 60 is located at point R, then bending can occur in a ZX plane which is located at—— some azimuth H 1 with respect to the preselected rotational orientation (for example, the upper side of the wellbore 12) in the plane orthogonal to the geometric axis of the wellbore 12. Generally, the geometric axis of the wellbore 12 may be substantially parallel to the geometric axis 70. Due to the bending effect, the magnetic moment of the transmitter 50 at T may be misaligned with respect to the connecting points of line T and R (line TR) by angle α, and nwhile the receiver 60 in R may be misaligned by angle β (it will actually be at angle 90°-β with respect to line TR). In the coordinate system where the geometric axis Z passes along the line TR and the geometric axis X rises to 90°, the transmitter's magnetic moment 50 (MT) can be represented by the superposition of magnetic moments Mz and Mx where:

    [00045] These two magnetic moments Mz, Mx can generate a magnetic field at receiver 60 which can be expressed by the following magnetic field components at point R: MzHx, MzHy, MzHz, MxHx, MxHy, MxHz. The total magnetic field in the R field can be expressed as:

    [00046] Tool 32 can rotate within well hole 12 at an angular frequency θ. This rotation may have no effect on the transmitter 50 due to the azimuthal symmetry of the coaxial magnetic moment MT, which means that Mz and Mx may be independent of the rotation of tool 32. The magnetic field components generated at point R may have the following projections on the rotating orthogonal magnetic moment of the receiver 60 (MR):

    [00047] Equations 1 & 3 can be substituted into equation 2 to obtain:

    [00048] To estimate the voltage at receiver 60, the following equation can be used:
    where ® is the angular frequency of the oscillating current in transmitter 60.
    [00049] If geotargeting is performed with tool 32 in a horizontally layered formation, the measurement signal can also be a function of 92 which is the orientation of the closest conductive layer in the plane orthogonal to the geometric axis of the wellbore 12. In some embodiments, tool 32 may include an azimuth resistivity tool.
    [00050] In some embodiments, complications can be introduced by a dependency on 92, however, equation 4 can be simplified by assuming: the bending angles α and β do not exceed 1° each for typical transmitter-receiver spacings (up to approximately 20 meters), then we can consider cosα = 1 and cosβ = 1, sinα.senβ = 0; only the angular dependence due to bending can be considered for components that have the direct field as the anomalous contribution to a remote bed is insignificant when a boundary between the layers is located relatively far from the tool, and Hxy is an anomalous component that can be neglected as this is multiplied by senα and does not have a direct field.
    [00051] Modifying equation 4 using the above assumptions can generate an equation as follows:

    [00052] Combining the first two terms in equation 6 can generate:
    where, as described above, j1 can be the phase relative to the azimuth of the folding and j2 can be the phase relative to the orientation of the closest conductive layer.
    [00053] The sum of two sinusoids with the same frequency is also a sinusoid so that equation 7 can be rewritten as:
    where 90 is the phase of the combined measured signal.
    [00054] In equation 8 the following parameters can be known: HbendZX - magnitude of the measured signal; 90 - the rotational phase of the measured signal; α, β - the bending angles, and 91 - the phase relative to the bending azimuth. In some embodiments, bending information sources may include, but are not limited to, one or more of: i) strain sensor measurements and ii) multi-frequency focusing measurements.
    [00055] Unknown parameters can include: HZX - amplitude of the cross component (signal we really need); 92 - azimuth of the closest conductive layer, HZZ, and HXX - main component signals.
    [00056] Although the above modality is described in terms of a Z transmitter and an X receiver, one skilled in the art with the benefit of this description would recognize that the equations can be modified for use as an X transmitter and a Z receiver.
    [00057] When tool 32 includes multiple transmitters 50, 51, and/or multiple receivers 60, 61, transmitters 50, 51 and receivers 60, 61 can be co-located. In the case of co-located multi-component measurements the HZZ, HXX signals can be estimated from the measurements and HZX of equation 8 to generate:

    [00058] However, the transmitters 50, 51 and/or receivers 60, 61 may be spaced far enough apart to be considered non-colocated. In this case, equation 8 can be incorporated into an inversion by constructing a "penalty" function to correct for differences introduced by non-co-localization of transmitters/receivers. Inversion techniques that can be used include, but are not limited to, one or more of: i) trial and error, ii) gradient optimization, and iii) simplex-based optimization. The inversion technique can be selected based on the complexity of the earth model used for the formation, direct solver speed for a synthetic field, or other considerations known to one skilled in the art. The penalty function can be constructed as follows:

    [00059] where Err can be a characterization of tool measurement accuracy and noise level; regularization terms can include constraints on parameters, terms responsible for faster convergence and/or a penalty value based on a degree of variance of an expected solution; and Fcost is the penalty function to be minimized in the inversion.
    [00060] Measured values can be Hbendzx and 90. Of the measured values, synthetic values (HZX, HZZ, HXX, and 92) can be recalculated at each step of a usage using a direct modeling algorithm. The folding parameters (α, β, 91) can be considered to be known, but mainly, they can be included as unknowns in the inversion algorithm. Typically there are several independent measurements available for use in inversion, including, but not limited to, one or more of: i) real components of voltages (signals) at different frequencies, ii) imaginary components of voltages at different frequencies, iii) real components of voltages at multiple points/depth ranges, and iv) imaginary components of voltages at multiple points/depth ranges.
    [00061] In some cases, the bending azimuth may be approximately the same as the orientation for the conductive bed, especially if the objective is to direct each to or from the bed. When the bending azimuth is approximately the same orientation for the conductive bed, the phases Φ0, Φ1, Φ2 can be considered equal:

    [00062] Fig. 7 shows a BHA 24 similar to Fig. 2, however, oriented transmitters 750, 751 are non-colocalized and oriented receivers 760, 761 are non-colocalized.
    [00063] Fig. 8 shows a flowchart of a method 800 according to an embodiment of the present description. At step 810, oriented transmitters 750, 751 and oriented receivers 760, 761 may be transported within wellbore 12. The BHA 24 may include one or more alignment sensors, such as strain sensors 35 (Fig. 7 ) and a third transmitter 52 (Fig. 3). Transmitters 750, 751 may be oriented substantially perpendicular to each other. In this example, transmitters 750, 751 are oriented in the Z and X directions, and their corresponding receivers 760, 761 are oriented in the X and Z directions. In step 820 energy can be transmitted into the terrestrial formation 13 using the oriented transmitters 750 , 751. In step 830, oriented receivers 760, 761 can generate signals indicative of the response of the terrestrial formation to the transmitted energy. The generated signals can be indicative of at least one resistivity property of the terrestrial formation. At step 840, a difference in alignment between each of the oriented transmitters 750, 751 and each of the corresponding substantially orthogonally aligned receivers 760, 761 may be estimated using an inversion of at least one measurement of at least one alignment sensor 35. In In some embodiments, alignment information can be estimated using an inversion of at least one measurement based on multi-frequency focusing information. The inversion can include inverting a folding correction equation, such as equation 8. In step 850, at least one processor can compensate for the BHA 24 warping effects on the receiver signals using the estimated difference in alignment. In step 860, at least one parameter of interest from the terrestrial formation 13 can be estimated using the receiver signals after compensation.
    [00064] Implicit in data processing is the use of a computer program implemented on a non-transient machine-readable medium that allows the processor to perform control and processing. The term processor as used in this application is intended to include such devices as field-programmable port networks (FPGAs). Non-transient machine readable media may include ROMs, EPROMs, EAROMs, Instant Memories and Optical Disks. As noted above, processing can be done downhole or on the surface using one or more processors. Furthermore, processing results, such as an image of a resistivity property, can be stored in a suitable medium.
    [00065] Although the above description is directed to that modality of mode of description, several modifications will be apparent to those skilled in the art. All variations are intended to be covered by the above description.
    权利要求:
    Claims (11)
    [0001]
    1. Method of conducting logging operations within a wellbore (12) that penetrates an onshore formation (13), characterized by comprising: compensating for misalignment effects between at least one oriented transmitter (50, 51) in an array of downhole (24) (BHA) and at least one receiver in the BHA on signals generated by the at least one oriented receiver (60, 61) using an inversion on at least one measurement from the signals generated by the at least one oriented transmitter ( 50, 51) in response to energy generated by the at least one oriented transmitter (50, 51); and estimate at least one parameter of interest for the terrestrial formation (13) using the signals generated by at least one oriented receiver (60, 61) after compensation for misalignment effects, wherein the at least one oriented receiver (60, 61) includes a among: i) a single oriented receiver (60, 61) and ii) a plurality of oriented receivers not co-located, and wherein the at least one oriented transmitter (50, 51) includes one of: i) a single oriented transmitter (50 , 51) and ii) a plurality of non-colocated oriented transmitters.
    [0002]
    The method of claim 1, further comprising: estimating the alignment information using an inversion of at least one measurement from the at least one alignment sensor (35), and wherein the compensation for misalignment effects using inversion comprises using alignment information indicative of alignment between the at least one oriented transmitter (50, 51) and the at least one oriented receiver (60, 61).
    [0003]
    A method according to claim 1, further comprising: estimating the alignment information using at least one of: (i) a strain gauge, (ii) a transmitter (50, 51) oriented at a non-X angle , not Z, (iii) a receiver oriented (60, 61) at an angle not X, not Z, (iv) a differential magnetometer, (v) a differential accelerometer, (vi) an optical sensor, and (vii) a fiber optic sensor; wherein compensating for the purposes of misalignment using inversion comprises using alignment information indicative of alignment between the at least one oriented transmitter (50, 51) and the at least one oriented receiver (60, 61).
    [0004]
    The method of claim 1, further comprising: estimating alignment information by: using a look-up table relating to bending moment measurements for acute angle severity; and using a look-up table relating to acute angle severity for misalignment angles; wherein compensating for the purposes of misalignment using inversion comprises using alignment information indicative of alignment between the at least one oriented transmitter (50, 51) and o at least one oriented receiver (60, 61).
    [0005]
    5. Method according to claim 1, characterized in that the received signals are indicative of an azimuth of a direction for a conductive layer in the terrestrial formation (13) closest to a geometric axis of the wellbore (12).
    [0006]
    6. Method according to claim 1, characterized in that estimating at least one parameter of interest comprises: generating the signals using the plurality of oriented receivers; and wherein compensating for the purposes of misalignment between the at least one oriented transmitter (50, 51) and the at least one oriented receiver (60, 61) in the signals using inversion comprises using alignment information indicative of alignment between the at least one oriented transmitter (50, 51) and the at least one oriented receiver (60, 61).
    [0007]
    7. Method according to claim 1, characterized in that the signals are indicative of at least one resistivity property of the terrestrial formation (13).
    [0008]
    8. Apparatus for conducting logging operations within a wellbore (12) penetrating an onshore formation (13), characterized in that it comprises: a downhole assembly (24) (BHA) configured to be transported within the wellbore. well (12); at least one oriented transmitter (50, 51) disposed on the downhole assembly (24) and configured to transmit energy into the terrestrial formation (13); at least one oriented receiver (60, 61) disposed on the downhole assembly (24) and configured to generate signals in response to the energy transmitted in the terrestrial formation (13) by at least one oriented transmitter (50, 51); at least one alignment sensor (35) disposed thereon. the downhole assembly (24) is configured to receive the alignment information, wherein the at least one oriented receiver (60, 61) includes one of: i) a single oriented receiver (60, 61) and ii) a plurality of oriented receivers not co-located, and in which at least one transm. This oriented transmitter (50, 51) includes one of: i) a single oriented transmitter (50, 51) and ii) a plurality of oriented transmitters not co-located; and at least one processor configured to: compensate for the effects of misalignment between the at least one oriented transmitter (50, 51) in a downhole assembly (24) (BHA) and the at least one oriented receiver (60, 61) in the BHA on signals generated by at least one oriented receiver (60, 61) using inversion over at least one measurement of signals generated by the at least one oriented receiver (60, 61) in response to energy generated by the at least one oriented transmitter ( 50, 51); and estimate at least one parameter of interest for the terrestrial formation (13) using the signals generated by the at least one oriented receiver (60, 61) after compensation for the effects of misalignment.
    [0009]
    9. Apparatus according to claim 8, characterized in that each of the plurality of oriented non-colocated receivers and the plurality of oriented non-colocated transmitters includes at least one coil.
    [0010]
    10. Apparatus according to claim 8, characterized in that at least one processor is further configured to: estimate alignment information using an inversion of at least one measurement of at least one alignment sensor (35); and wherein compensating for the purposes of misalignment using inversion comprises using alignment information indicative of alignment between the at least one oriented transmitter (50, 51) and the at least one oriented receiver (60, 61).
    [0011]
    11. Apparatus according to claim 8, characterized in that at least one alignment sensor (35) includes at least one of: (i) a strain gauge, (ii) an oriented transmitter (50, 51) in a non-X, non-Z angle, (iii) a receiver oriented (60, 61) at a non-X, non-Z angle, (iv) a differential magnetometer, (v) a differential accelerometer, (vi) an optical sensor, and ( vii) a fiber optic sensor.
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    同族专利:
    公开号 | 公开日
    GB2521058B|2016-06-15|
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    NO20140926A1|2015-02-09|
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    法律状态:
    2018-12-04| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2020-02-18| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2021-05-11| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-07-20| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 06/05/2013, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
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    US13/469,927|US9091791B2|2012-05-11|2012-05-11|Accounting for bending effect in deep azimuthal resistivity measurements using inversion|
    US13/469,927|2012-05-11|
    PCT/US2013/039673|WO2013169638A1|2012-05-11|2013-05-06|Accounting for bending effect in deep azimuthal resistivity measurements using inversion|
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