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    • 专利摘要:
    METHOD AND APPARATUS FOR CONDUCTING PROFILE OPERATIONS IN WELL HOLE AND COMPUTER-READABLE MEDIUM PRODUCT. The present invention relates to an apparatus and method for estimating a parameter of interest of a terrestrial formation involving the alignment information between the receivers and their corresponding oriented transmitters. The method may include generating signals indicative of responses to energy transmitted into a terrestrial formation; estimating differences in alignment between transmitters and receivers, using the estimated differences in alignment to compensate for misalignment, and estimating a parameter of interest using the offset non-aligned signals. The apparatus may include the downhole assembly (24) with one or more oriented transmitters, one or more oriented receivers, one or more alignment sensors, and at least one processor (36) configured to compensate for misalignment using information about the difference in alignment between the at least one oriented transmitter (50, 51) and the at least one oriented receiver (60, 61).
    公开号:BR112014021162B1
    申请号:R112014021162-0
    申请日:2013-05-09
    公开日:2021-05-18
    发明作者:Andreas Hartmann；Christian Fulda；Hans-Martin Maurer
    申请人:Baker Hughes Incorporated；
    IPC主号:
    专利说明:

    Description field
    [001] This description generally refers to the exploration of hydrocarbons involving electrical investigations of a well hole (borehole) penetrating a terrestrial formation. Description Background
    [002] In downhole operations such as drilling, geographic targeting, and measurement during drilling (MWD) operations, sensor devices are included with a wellbore that measures the various parameters of a formation and /or a wellbore. Such sensor devices are typically arranged to have a desired orientation or alignment, and 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 accuracy of spiral positioning during tool fabrication and/or assembly and tool bending during logging operation. Navigation through a terrestrial formation can result in sensor devices shifting from a desired alignment, including carrier deformation along which the sensor devices can be positioned. The bending effect can be significant for deep reading of azimuth tools with large spacings between transmitter and receiver. Description Summary
    [003] In aspects, the present description is related to methods and apparatus estimating at least one parameter of interest while compensating for differences in alignment between oriented transmitters and receivers.
    [004] An embodiment according to the present description includes a method of conducting logging operations in a wellbore penetrating a terrestrial formation, comprising: estimating at least one parameter of interest of the terrestrial formation using signals generated by at least one oriented receiver in a downhole assembly in response to energy generated by at least one oriented transmitter in the downhole assembly and information indicative of alignment between the at least one oriented transmitter and the at least one oriented receiver, where the at least a oriented receiver includes one of: (i) a single oriented receiver and (ii) a plurality of co-located oriented receivers, and where the at least one oriented transmitter includes one of: (i) a single oriented transmitter and (ii) a plurality of colocalized oriented transmitters.
    [005] Another embodiment according to the present description includes an apparatus for conducting logging operations in a wellbore penetrating an onshore formation, comprising: a downhole assembly configured to be transported in the wellbore; at least one oriented transmitter disposed in the downhole assembly and configured to transmit energy into the terrestrial formation; at least one oriented receiver disposed in the downhole assembly and configured to receive a signal from the ground formation; at least one alignment sensor disposed in the downhole assembly and configured to receive alignment information; where the at least one oriented receiver includes one of: (i) a single oriented receiver and (ii) a plurality of colocalized oriented receivers, and where the at least one oriented transmitter includes one of: (i) a single oriented transmitter and (ii) a plurality of colocalized oriented transmitters; and at least one processor configured to: estimate at least one terrestrial formation parameter of interest using information from signals generated by at least one oriented receiver.
    [006] Another embodiment according to the present description includes a non-transient computer-readable medium product having stored in it instructions that, when executed by at least one processor, cause at least one processor to perform a method, the method comprising: estimating at least one parameter of interest of a terrestrial formation using signals generated by at least one receiver oriented in a downhole assembly in response to energy generated by at least one transmitter oriented in 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 one oriented receiver includes one of: (i) a single oriented receiver and (ii) a plurality of colocalized oriented receivers and where the at least one steered transmitter includes one of: (i) a single steered transmitter and (ii) a plurality of steered transmitters co-located.
    [007] Another modality according to the present description includes a method of conducting logging operations in a well hole penetrating a terrestrial formation, comprising: estimating at least one parameter of interest of the terrestrial formation using signals generated by the at least one oriented receiver in a downhole assembly in response to energy generated by at least one oriented transmitter in the downhole assembly and information indicative of the alignment between the at least one transmitter and the at least one oriented receiver, where the at least one oriented receiver includes one of: (i) a single oriented receiver and (ii) a plurality of non-colocated oriented receivers, and where the at least one oriented transmitter includes one of: (i) a single oriented transmitter oriented and (ii) a plurality of non-colonized oriented transmitters.
    [008] Another embodiment according to the present description includes an apparatus for conducting logging operations in a wellbore penetrating an onshore formation, comprising: a downhole assembly configured to be transported in the wellbore; at least one oriented transmitter disposed in the downhole assembly and configured to transmit energy into the terrestrial formation; at least one oriented receiver disposed in the downhole assembly and configured to receive signals from the ground formation; at least one alignment sensor disposed in the downhole assembly and configured to receive alignment information, wherein the at least one oriented receiver includes one of: (i) a single oriented receiver and (ii) a plurality of oriented receivers non-co-localized, and where the at least one oriented transmitter includes one of: (i) a singular oriented transmitter and (ii) a plurality of non-co-localized oriented transmitters; and at least one processor configured to: estimate at least one terrestrial formation parameter of interest using information from the signals generated by the at least one oriented receiver.
    [009] Another modality according to the present description includes a non-transient computer-readable medium product having stored in it instructions that, when executed by at least one processor, cause the at least one processor to perform a method, the method comprising: estimating at least one parameter of interest of a terrestrial formation using signals generated by at least one receiver oriented in a downhole assembly in response to energy generated by at least one transmitter oriented in the downhole assembly and information indicative of alignment between the at least one oriented transmitter and the at least one oriented receiver, where the at least one oriented receiver includes one of: (i) a single oriented receiver and (ii) a plurality of non-oriented receivers. colocalized, and where the at least one steered transmitter includes one of: (i) a single steered transmitter and (ii) a plurality of steered transmitters not co-located.
    [0010] Examples of the most important features of the description have been summarized very broadly so that the detailed description that follows can be better understood and so that the contributions they represent to the technique can be appreciated. Brief Description of Drawings
    [0011] For a detailed understanding of the present description, reference should be made to the following detailed description of the modalities, taken into consideration in conjunction with the attached drawings, in which similar elements have received similar numerical references, in which:
    [0012] FIG. 1 illustrates a schematic of a downhole assembly (BHA) developed in a well along a drill string in accordance with an embodiment of the present description;
    [0013] FIG. 2 illustrates a schematic approximation of a modality of a resistivity tool in the BHA with strain sensors and with colocated transmitters and colocated receivers configured for developing a well in accordance with an embodiment of the present description;
    [0014] FIG. 3 illustrates a schematic approach of another embodiment of a resistivity tool in the BHA with a third transmitter configured for development in a well in accordance with an embodiment of the present description;
    [0015] FIG. 4 illustrates a flowchart of a method for estimating at least one parameter of interest according to an embodiment of the present description;
    [0016] FIG. 5 illustrates an amplitude vs. distance plot for boundary curves based on receiver signals before and after strain compensation;
    [0017] FIG. 6 illustrates a schematic of a transmitter and receiver combination with associated magnetic pulses in accordance with an embodiment of the present description;
    [0018] FIG. 7 illustrates a schematic approximation of another embodiment of a resistivity tool in the BHA with non-colocated transmitters and non-colocated receivers configured for deployment in a well in accordance with an embodiment of the present description; and
    [0019] FIG. 8 illustrates a flowchart of a method for estimating at least one parameter of interest according to another embodiment of the present description. Detailed Description
    [0020] This description generally refers to hydrocarbon exploration involving electromagnetic investigations of a wellbore penetrating a terrestrial formation. Such investigations may include estimating at least one terrestrial formation parameter of interest and using the additional alignment information to compensate for misalignment between transmitters and receivers, such as due to deformation of a carrier.
    [0021] The present description is susceptible to the modalities in different ways. Specific embodiments of the present description are illustrated in the drawings and will be described in detail herein with the understanding that the present description is to be considered an illustration of the principles of the description and should not limit the description to that illustrated and described herein. Indeed, as will become apparent, the teachings in the present description can be used for a variety of well tools and in all phases of well construction and production. Accordingly, the modalities discussed below are merely illustrative of the applications of the present description.
    [0022] FIG. 1 illustrates an illustrative embodiment of a well drilling system, the logging operation and/or geographic targeting 10 including a drill string 11 that is illustrated disposed in a wellbore or well 12 that penetrates at least one onshore formation 13 during a drilling operation and performs measurements of the properties of formation 13 and/or wellbore 12 at the downhole. As described here, "wellbore" or "well" refers to a single hole that creates all or part of a drilled well. As described here, "formations" refers to the various features and materials that can be found in a subsurface environment and that surround the wellbore. The term "information" includes, but is not limited to raw data, processed data and signals.
    [0023] In one embodiment, the system 10 includes a conventional crane 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 extends down and into the wellbore 12 from the rotary table 16 and is connected to a drill assembly 20. The drilling fluid or mud rig 22 is pumped through the drill string 11 and/or wellbore 12. The well drilling system 10 also includes a downhole assembly (BHA) 24. In one embodiment, a drill motor or drilling motor mud 26 is coupled to drilling assembly 20 and rotates drilling assembly 20 as drilling fluid 22 is passed through the mud motor 26 under pressure.
    [0024] In one embodiment, the drill assembly 20 includes a steering assembly including an axle 28 connected to a drill bit 30. The axle 28, which in one embodiment is coupled to the mud motor, is used in steering operations to drive drill bit 30 and drill string 11 through the formation.
    [0025] In one embodiment, the drilling assembly 20 is included in the downhole assembly (BHA) 24, which is disposed within the system 10 at or near the downhole of the drill string 11. The system 10 includes any number of downhole tools 32 for various processes including formation drilling, geographic targeting and formation evaluation (FE) for measuring x depth and/or time of one or more physical quantities in or around a wellbore . Tool 32 may be included in or embodied as a BHA, drill string component or other suitable carrier. A "carrier" as described herein means any device, device component, combination of devices, means and/or element that can be used to transport, house, support or otherwise facilitate the use of another device, device component, combination of devices, medium and/or element. Illustrative non-limiting carriers include coiled piping type, spliced piping type drill strings, and any combination or part. Other carriers include, but are not limited to, casing tubes, cable lines, cable rigs, taut cable rigs, drop shots, downhole subsurface (subs), downhole assemblies, and drill strings.
    [0026] 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 formation and/or wellbore. For example, one or more parameter 34 sensors (or sensor sets such as subsurface MWD) are configured for formation evaluation measurements and/or other parameters of interest (referred to herein as "evaluation parameters") relating to the formation , wellbore, geophysical characteristics, wellbore fluids and boundary conditions. These sensors 34 may include formation evaluation sensors (eg resistivity, dielectric constant, water saturation, porosity, density and permeability), sensors for measuring wellbore parameters (eg wellbore size, slope of wellbore and azimuth and wellbore roughness), sensors for measuring geophysical parameters (eg acoustic velocity, acoustic travel time, electrical resistivity), sensors for measuring wellbore parameters (eg viscosity , density, clarity, rheology, pH level, and gas, oil and water content), boundary condition sensors and sensors for measuring the physical and chemical properties of the wellbore fluid.
    [0027] System 10 also includes sensors 35 for measuring force, operating and/or environmental parameters related 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 deformation, 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 deformation or bending that can result in a change in position, alignment and/or orientation of one or more sensors 34. In a non-limiting modality, the sensors 35 may include one or more of (i) a strain gauge, (ii) a transmitter oriented at an angle other than X and Z, (iii) a receiver oriented at an angle other than X and Z, (iv) a differential magnetometer, (v) a differential accelerometer, (vi) an optical sensor, and (vii) a fiber optic sensor.
    [0028] For example, a distributed sensor system (DSS) is disposed on the drill string 11 and 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 thus result in misalignment of one or more sensors 34. A non-limiting example of the measurements performed by sensors 35 include accelerations, velocities, distances, angles, forces, impulses and pressures. Sensors 35 can also be configured to measure environmental parameters such as temperature and pressure. In a non-limiting example, sensors 35 can be distributed throughout an entire drill string and tool (such as a drill bit) at the distal end of drill string 11. In other embodiments, sensors 35 can be configured to measure the steering characteristics at various locations along wellbore 12. Examples of such steering characteristics include slope and azimuth, curvature, stress, and bending moment.
    [0029] FIG. 2 illustrates a downhole component, such as a drill pipe section or BHA 24 that includes a plurality of strain sensors 35 incorporated into a drill sensor sub 37 and disposed along an axis of the column portion. of perforation. 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 pressure, and annular and instrument 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, bend tool face angle, and bend face angle. well tool. Other non-limiting examples of the sensors 35 include magnetometers and inclinometers configured to provide tilt data. The use of a plurality of strain sensors 35 is illustrative and illustrative only, as some embodiments of the present description can be realized with a single strain sensor 35.
    [0030] An illustrative 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 the directions to express the deformation of sub 37 in the wellbore. In one embodiment, sensors 35 are configured to perform independent perpendicular bending moment measurements at selected transverse locations of tool 32. For example, strain gauges 38 and 40 are configured to perform bending moment measurements along the tool. geometric axis x and y, respectively.
    [0031] Generally, some of the teachings presented here are reduced to an algorithm that is stored on 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 real-time data to surface processing unit 36 via cable, or by any type of telemetry such as mud pulse telemetry. or pipes with wires during a drilling or measurement-while-drilling (MWD) operation.
    [0032] In one embodiment, parameter sensors 34, strain sensors 35 and/or downhole components include and/or are configured to communicate with at least one processor to receive, measure and/or estimate characteristics directional and other characteristics of 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 illustrated). Such transmission equipment can take any desired shape, and different transmission means and connections can be used. Examples of connections include, but are not limited to, wired, fiber optics, acoustics, wireless connections, and mud pulse telemetry.
    [0033] The at least one processor can be configured to receive data and generate information such as a mathematical model for estimating and predicting bending or other deformation of various components. For example, the at least one processor can be configured to receive downhole data in addition to additional data (eg, from a user or database) such as wellbore size and wellbore component geometric data. such as component and material size/shape. In one embodiment, the surface processing unit 36 is configured as a surface drilling control unit that controls various drilling parameters such as rotational speed, weight on the drill, drilling fluid flow parameters, and so on. 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. Illustrative components include, without limitation, at least one processor, store, memory, input devices, output devices, and the like.
    [0034] Since the drill string 11 may bend within a wellbore, transmitters 50, 51 and receivers 60, 61 that are arranged in the BHA 24 or otherwise along the drill string 11 may undergo alignment changes 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 the alignment of a transmitter and 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 utilize intertwined spirals or spirals separated in such proximity so as to behave as a point transmitter/receiver as understood by those skilled in the art. Two receiver/transmitter positions can be considered colocalized if the received signals, due to the energy emitted by the transmitters, at both positions are substantially identical within the selected measurement accuracy. Non-co-located transmitters/receivers are not intertwined and are separated by sufficient distance so as to behave as individual transmitters/receivers as understood by those skilled in the art. In this way, two receiver/transmitter positions can be considered not co-located if the received signals, due to the energy emitted by the transmitters, 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. The alignment between 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 can be positioned to provide information indicative of deformation along geometric axes relevant to the orientation of transmitters 50, 51 and receivers 60, 61. For example, the direction of deformation can be estimated using deformation sensors 35 distributed around the circumference of the sub 37. While FIG. 2 illustrates the oriented transmitters 50, 51 and oriented receivers 60, 61 in an alternating ZX pattern, this is illustrative only, as the transmitters and receivers can be oriented in any combination of orientation including combinations with a triaxial antenna such as the Z transmitter with an XYZ receiver (not shown). In some embodiments, the oriented transmitters 50, 51 may include spirals configured so that the spirals of the transmitter 50 and the transmitter 51 are wrapped around each other and/or spaced in such proximity as to be co-located as would be understood. by those skilled in the art. Similarly, oriented receivers 60, 61 may include spirals configured such that the spirals of receiver 60 and receiver 61 are wrapped around each other and/or spaced in such proximity as to be co-located as would be understood by those skilled in the art. technique. Some modalities may only use a single transmitter and a single receiver.
    [0035] In some embodiments, alignment information can be estimated using a wellbore direction change radius (such as a curve in the local dogleg) from a measured bending moment. Downhole curve severity is a measure of a change in the direction of a wellbore within a given length of the wellbore. The curve severity in the well can be stored as a function of the bending moment. Precalculated values for the bending moment can be stored in a lookup table. Another look-up table may include pre-calculated values for a misalignment angle between at least one transmitter 50, 51 and its corresponding receiver 60, 61. The misalignment angle look-up table may illustrate the misalignment angle alignment as a function of the curve severity in the well. For a measured depth in wellbore 12, a local wellbore turn 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 the curve severity in the local well and using the second look-up table.
    [0036] FIG. 3 illustrates another embodiment in accordance with the present description, where a third transmitter 52 (or receiver 62) may be used in place of strain sensors 34. Using two pairs of oriented transmitters 50, 51 and oriented receivers 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 εT). In FIG. 3, the angle εt (or εT) is illustrated in the X-Y plane, however this is illustrative only, since the angle εt (or εT) can be oriented in any direction. In some embodiments, only the third transmitter 52 or only the third receiver 62 can be present.
    [0037] FIG. 4 illustrates a flowchart of a method 400 according to an embodiment of the present description. In step 410, oriented transmitters 50, 51 and oriented receivers 60, 61 may be carried in wellbore 12 along with one or more strain sensors 35 (FIG. 2) and/or a third transmitter 52 (FIG. 3 ). Transmitters 50, 51 can be oriented substantially perpendicular to each other. Similarly, the receivers 60, 61 can 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 orientation transmitters 50, 51. In step 430, oriented receivers 60, 61 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. In step 440, a difference in alignment between each of the oriented transmitters 50, 51 and the substantially orthogonally aligned receivers 60, 61 can be estimated. In step 450, at least one processor can compensate for the effects of BHA 24 strain 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 signals from the receiver after compensation.
    [0038] Once the difference in alignment angles is estimated, signals generated by receivers 60, 61 in response to the energy emitted by transmitters 50, 51 can be modified to compensate for misalignment between individual transmitters 50, 51 and the receivers 60, 61.
    [0039] In the modalities using one or more deformation sensors 35 (FIG. 2), to compensate the deformation of the BHA 24 may include the application of a set of algorithms using the estimated differences in the alignment. Deformation compensation may include compensation for misalignment due to an angular change between transmitters and receivers and a deviation (e.g., off axis) between the relative positions of the transmitters and receivers due to deformation of the BHA 24. Angular change can be addressed with the following illustrative equations:
    [0040] Amp ZZ measured = Amp ZZ true * cos(Deformation) + Amp ZX true * sin(Deformation)
    [0041] AMP ZX measured = Amp ZZ true * sin(Deformation) + Amp ZX true * cos(Deformation)
    [0042] Amp XZ measured = Amp XZ true * cos(Deformation) + Amp XX true * sin(Deformation)
    [0043] Amp XX measured = Amp XZ true * sin(Deformation) + Amp XX true * cos(Deformation)
    [0044] where, Amp AB is the amplitude of the signal from transmitter A to receiver B; X represents the crossover receiver/transmitter; and Z represents the axial receivers/transmitters.
    [0045] In modalities using a third transmitter oriented at an angle ε in the X-Z plane, the BHA 24 strain compensation may include the application of a set of algorithms using the estimated differences in alignment with the following illustrative equations:
    [0046] Measured RX Amp = True ZZ Amp * sin(Deformation) + True ZX Amp * cos(Deformation)
    [0047] Amp RZ measured = Amp ZZ true * cos(Deformation) + Amp ZX true * sin(Deformation)
    [0048] Amp RT measured = Amp ZZ true * sin(Deformation + ε) + Amp ZX true * cos(Deformation + ε)
    [0049] where, Amp RB is the amplitude of the signal received at receiver R from transmitter B, X represents the cross transmitter, Z represents the axial transmitter, and T represents the transmitter tilted at an angle εt (or εT). The three measurements (Measured Amp RX, Measured Amp RZ, and Measured Amp RT) can be used to resolve True Amp ZZ, True Amp ZX, and True Amp XX.
    [0050] In the event that a receiver becomes positioned outside the geometric axis, the following illustrative equation can be used to compensate:
    [0051] Amp XZ measured =

    [0052] where ^-Ll is the magnetic field vector on the longitudinal geometric axis 70, β is the angle of misalignment of the receiver, is the magnetic field vector due to the off position of the geometric axis of the receiver, is the vector of magnetic field due to an inhomogeneous part of the terrestrial formation 13, and is the sensitivity vector of the receiver 60, 61. For small strain angles β and a large distance to the remote bed (the application case), the created field by the inhomogeneous medium it can be approximately homogeneous in the antenna within the range of position variation caused by the deformation so that the off-axis component, ie change of this field due to the receiver's position change, need not be considered.
    [0053] The at least one parameter of interest of terrestrial formation can be estimated using "true" amplitudes obtained after compensation for the deformation of the BHA 24. The at least one parameter of interest may include, but is not limited to, the one or more of: (i) complex conductivity/resistivity (ie, real and imaginary part), (ii) dielectric constant, (iii) boundary distance, and (iv) remote bed resistivity (ie, one-layer resistivity behind a limit). In some modalities, XZ signal strength and/or ZX signal tool face direction can also be estimated. In some cases, the deformation of a section of wellbore 12 can be estimated in a separate logging operation that runs from the logging operation where signals are generated by receivers 60, 61.
    [0054] FIG. 5 illustrates a graph with curves representing the signals generated by the receivers 60, 61 before and after deformation correction. Curve 510 represents the amplitude/limit distance response of the multi-component propagation resistivity tool before strain compensation. Curve 520 represents the amplitude/threshold distance response after compensating for alignment differences between the oriented transmitters and oriented receivers.
    [0055] FIG. 6 illustrates a schematic of a transmitter and receiver configuration with magnetic pulse orientations. In some embodiments, bending effects can be observed in the HZX measurement (one or more of the real or imaginary components of HZX), where Z is the orientation of receiver 60 substantially perpendicular to the geometric axis of tool 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 that is located at some azimuth 91 with respect to the preselected rotational orientation (eg, the top 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 axis 70. Due to the bending effect, the magnetic impulse of the transmitter 50 at T may not be aligned with respect to the connecting points of line T and R (line TR) by angle a, while receiver 60 at R may not be aligned by angle β (it will actually be at angle 90 -β with respect to the TR line). In the coordinate system where the Z axis follows the TR line and the X axis rises to 90°, the transmitter's magnetic impulse 50 (MT) can be represented by the superposition of the magnetic impulses Mz and Mx where: Mx = MT • cos The; Mx = MT • sin a; (1)
    These two magnetic pulses Mz, Mx can generate a magnetic field at receiver 60 which can be expressed as the following magnetic field components at point R: MzHx, MzHyMxHx, MxHy, MxHz. The total magnetic field at point R can be expressed as:

    [0057] Tool 32 can rotate in wellbore 12 at an angular frequency θ. This rotation may have no effect on the transmitter 50 due to the azimuth symmetry of the coaxial magnetic pulse 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 in the orthogonal magnetic pulse of rotation of the receiver 60 (MR): Hz sin β • COS(Θ-ΦI); Hx cos β • COS(Θ-ΦI); HY sin(θ-Φ1); (3)
    [0058] Equations 1 and 3 can be replaced by equation 2 to obtain:

    [0059] 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.
    [0060] If the geographic targeting is performed with the tool 32 in the formation in horizontal layers, the measured 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.
    [0061] In some modalities, complications can be introduced by a dependency of 92, however, equation 4 can be simplified by assuming:
    [0062] i) the bend angles α and β do not exceed 1 each for typical transmitter and receiver spacings (up to about 20 meters), so one can consider cosα=1 and cosβ = 1, sinα»sinβ = 0 ; and
    [0063] ii) only angular dependence due to bending can be considered for components that have the direct field since the anomalous contribution of a remote bed is negligible when a boundary between the layers is located relatively far from the tool, and
    [0064] iii) Hxy is an anomalous component that can be neglected since it is multiplied by sinα and does not have a direct field.
    [0065] Modifying equation 4 using the above considerations can result in an equation as follows:

    [0066] The combination of the first two terms in equation 6 can result:
    where, as described above, 91 can be the phase related to the azimuth of the bend and 92 can be the phase related to the orientation of the closest conductive layer.
    [0067] 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.
    [0068] In equation 8 the following parameters can be known- J magnitude of the measured signal; 90 - the phase of rotation of the measured signal; α, β - the bend angles, and 91 - the phase related to the bend azimuth. In some embodiments, bending information sources may include, but are not limited to, one or more of: (i) voltage sensor measurements and (ii) multi-frequency focus measurements.
    [0069] Unknown parameters may include: HZX - cross component amplitude (signal that was actually needed); 92 - azimuth of the nearest conductive layer, HZZ and HXX - main component signals.
    [0070] While the above modality is described in terms of a Z transmitter and an X receiver, those skilled in the art with the benefit of this description will recognize that the equations can be modified for use with an X transmitter and a Z receiver.
    [0071] When tool 32 includes multiple transmitters 50, 51 and/or multiple receivers 60, 61, transmitters 50, 51 and/or receivers 60, 61 can be co-located. In the case of measurements of multiple components co-located HZZ signals, HXX can be estimated from the measurements and HZX of equation 8 to result:

    [0072] 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 the deficiencies introduced by the 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, speed of the direct solver to a syntactic field, or other considerations known to those skilled in the art. The penalty function can be constructed as follows:
    where Err can be a characterization of tool measurement accuracy and noise level: smoothing terms can include constraints on parameters, terms responsible for faster convergence, and/or a penalty value based on a degree variation of an expected solution; and Fcost is the penalty function to be minimized in the inversion.
    [0073] The measured values can be ir- and 90. From the measured values, the synthetic values (HZX, HZZ, HXX, and 92) can be re-calculated in each step of an optimization using a modeling algorithm of advance. The bending parameters (α, β, 91) can be considered known, but in principle, they can be included as unknowns in the inversion algorithm. Typically, there are several independent measurements available for use in inverting, 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 points/intervals of multiple depths, and (iv) imaginary components of voltages at points/intervals of multiple depths.
    [0074] In some cases, the bending azimuth can be almost equal to the orientation to the conductive bed, especially if the objective is to direct to or from the bed. When the bending azimuth is almost equal to the orientation of the conductor bed, the phases Φ0, Φ1, Φ2 can be considered equal:

    [0075] FIG. 7 illustrates BHA 24 similar to FIG. 2, however, oriented transmitters 750, 751 are not co-localized and oriented receivers 760, 761 are not co-localized.
    [0076] FIG. 8 illustrates 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 carried in 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. Similarly, receivers 760, 761 can be oriented substantially perpendicular to one another. 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 may generate signals indicative of the response of the terrestrial formation to the transmitted energy. The generated signals can be indicative of at least one resistive property of the terrestrial formation. In 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 can be estimated using an inversion of at least one measurement of the at least one sensor. alignment 35. In some embodiments, alignment information can be estimated using an inversion of at least one measurement based on focus information from multiple frequencies. The inversion can include the inversion of a warp correction equation, such as equation 8. In step 850, at least one processor can compensate for the effects of BHA deformation 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.
    [0077] Implicit in data processing is the use of a computer program implemented in a suitable non-transient machine readable medium that allows the processor to perform control and processing. The term processor as used in this order shall include such devices as field-programmable tip assemblies (FPGAs). Non-transient machine readable media may include ROMs, EPROMs, EAROMs, Flash Memory and Optical disks. As noted above, processing can be done downhole or on the surface, using one or more processors. Additionally, processing results, such as an image of a resistivity property, can be stored in a suitable medium.
    [0078] While the above description is directed to the modalities of a mode of description, various modifications will be apparent to those skilled in the art. All variations are intended to be encompassed by the above description.
    权利要求:
    Claims (14)
    [0001]
    1. Method of conducting logging operations in a wellbore penetrating an onshore formation, characterized by comprising: estimating alignment information indicative of an angular change between at least one oriented transmitter (50, 51) over a bottom set of well (24) (BHA) and at least one receiver oriented (60, 61) in the BHA using BHA strain measurements from at least one strain sensor; using the alignment information to compensate for the effects of misalignment between the at least one oriented transmitter (50, 51) and the at least one oriented receiver (60, 61) on 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), the compensation comprising applying a compensation algorithm to the signals generated by the at least one oriented receiver (60, 61); and estimating at least one terrestrial formation parameter of interest using compensation, wherein the at least one strain sensor includes at least one of: (i) a strain gauge, (ii) a oriented transmitter (50, 51) at a non-X, non-Z angle, (iii) an oriented receiver (60, 61) at a non-X, non-Z angle, (iv) a magnetometer, (v) an accelerometer, (vi) a sensor distance, (vii) an optical sensor, and (viii) a fiber optic sensor.
    [0002]
    2. Method according to claim 1, characterized in that the estimation of the at least one parameter of interest comprises: the generation of signals using the at least one oriented receiver (60, 61).
    [0003]
    3. Method according to claim 1, characterized in that the at least one formation sensor includes at least one of: (i) the magnetometer, and (ii) the accelerometer; wherein the magnetometer comprises a differential magnetometer and the accelerometer comprises a differential accelerometer.
    [0004]
    4. Method according to claim 1, characterized in that the estimation of alignment information comprises: use of a look-up table referring to bending moment measurements for the severity of the curve in the well; and use of a look-up table regarding the severity of the curve in the well for the misalignment angles.
    [0005]
    5. Method according to claim 1, characterized in that the signals are indicative of at least one resistivity property of the terrestrial formation.
    [0006]
    6. Method according to claim 1, characterized in that the at least one parameter of interest includes at least one of: (i) complex conductivity / resistivity, (ii) dielectric constant, (iii) boundary distance, and (iv) remote bed resistivity.
    [0007]
    7. Method according to claim 1, characterized in that it further comprises: the transport of at least one transmitter and at least one receiver in the wellbore.
    [0008]
    8. Apparatus for conducting logging operations in a wellbore penetrating an onshore formation, characterized by comprising: a downhole assembly (24) configured to be transported in the wellbore; at least one oriented transmitter (50, 51) disposed in the downhole assembly (24) and configured to transmit energy into the terrestrial formation; at least one oriented receiver (60, 61) disposed in the downhole assembly (24) and configured to receive a signal from the terrestrial formation, wherein the at least one strain sensor includes at least one of: (i) a meter voltage, (ii) a transmitter oriented (50, 51) at an angle not-X, not-Z, (iii) a receiver oriented (60, 61) at an angle not-X, not-Z, (iv) a magnetometer, (v) an accelerometer, (vi) a distance sensor, (vii) an optical sensor, and (viii) a fiber optic sensor; and at least one processor (36) configured to: estimate alignment information indicative of an angle change between the at least one oriented transmitter (50, 51) in the BHA and the at least one oriented receiver (60, 61) in the BHA using measurements of BHA strain from the at least one strain sensor, use the alignment information to compensate for the effects of misalignment between the at least one oriented transmitter and the at least one oriented receiver (60, 61) on 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), the compensation comprising applying a compensation algorithm to the signals generated by the at least one oriented receiver (60, 61 ); and estimate at least one parameter of interest for the terrestrial formation using compensation.
    [0009]
    9. Apparatus according to claim 8, characterized in that the at least one receiver and the at least one transmitter include at least one spiral.
    [0010]
    10. Apparatus according to claim 8, characterized in that the at least one processor (36) is additionally configured to: use a look-up table referring to bending moment measurements for curve severity in the well; and use a look-up table regarding the severity of the curve in the well for misalignment angles.
    [0011]
    11. Apparatus according to claim 8, characterized in that the at least one strain sensor includes at least one of: (i) a magnetometer and (ii) an accelerometer; wherein the magnetometer comprises a differential magnetometer, and the accelerometer comprises a differential accelerometer.
    [0012]
    12. Apparatus according to claim 11, characterized in that at least one strain gauge is disposed on the carrier at a location between the at least one oriented receiver (60, 61) and the at least one oriented transmitter (50 , 51).
    [0013]
    13. Apparatus according to claim 8, characterized in that the signals are indicative of a resistivity property of the terrestrial formation.
    [0014]
    14. Apparatus according to claim 8, characterized in that at least one parameter of interest includes at least one of: (i) complex conductivity/resistivity, (ii) dielectric constant, (iii) boundary distance, and ( iv) remote bed resistivity.
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    同族专利:
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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]|
    2020-07-28| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2020-12-08| B06A| Notification to applicant to reply to the report for non-patentability or inadequacy of the application [chapter 6.1 patent gazette]|
    2021-04-13| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-05-18| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 09/05/2013, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
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    US13/469,978|US9062540B2|2012-05-11|2012-05-11|Misalignment compensation for deep reading azimuthal propagation resistivity|
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    PCT/US2013/040261|WO2013169975A1|2012-05-11|2013-05-09|Misalignment compensation for deep reading azimuthal propagation resistivity|
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