Patent Description:
Ranging techniques are used to determine distance and direction between wellbores in geological formations. Ranging techniques (which can assist in well planning) can involve drilling wellbore in close proximity to one or more existing wellbores. Placing multiple wellbores in close proximity may be advantageous in many drilling operations and well plans. For example, dense placement of wellbores may reduce environmental impact as well as maximize available space in areas where there is a limited amount of available area for wellheads (for example an offshore platform). Such wellbores may extend to a certain depths and direction in parallel before branching out before a "kick-off" point where the wellbores extend away. Certain oil drilling methods such as steam assisted gravity drainage (SAGD) requires shallow horizontal wellbore pairs to be drilled in parallel and can require ranging techniques.

There are various ranging techniques which allow construction of a wellbore in close proximity to an existing well, also known as a target wellbore. Active ranging is a ranging technique where an electromagnetic (EM) source is placed in the target wellbore and monitored via sensors on the drill string in the wellbore under construction. Active ranging methods however has significant drawbacks such as requiring access to both the drilling wellbore and target well, halt in production from the target well, and extensive use in equipment. Active ranging is also sensitive to precise axial alignment between the magnetic source deployed in the target wellbore and the sensor in the drilling well. Misalignment may result in misplacement of the drilling wellbore that decreases well productivity. Ensuring proper alignment in active ranging methods is labor and time intensive and may be difficult to carry out especially in wellbores that are deep.

Passive ranging avoids many of the limitations that exists in active systems. Passive ranging is a ranging technique that applies a current on the wellbore casing of the target wellbore to generate an EM field around the target well. A current source, often a low-frequency current, is connected to a target wellbore which results in currents flowing down the wellbore and leaking into the surrounding formation. This EM field may be detected by an EM field sensor system disposed in the drilling well. Document <CIT> describes that the structural integrity and reliability of a downhole tool or mandrel may be improved by implementation of a design and configuration that does not require several separate components to be coupled together.

The invention relates to a method as defined in claim <NUM>, a system as defined in claim <NUM> and one or more non-transitory machine-readable media comprising instructions as defined in claim <NUM>. Other aspects of the invention are defined in the dependent claims.

The description that follows includes example systems, methods, techniques, and program flows that embody embodiments of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to running a current through the target wellbore casing in illustrative examples. Aspects of this disclosure can also be applied to any conductive member running coaxially along the length of the wellbore and the target wellbore may either be cased or uncased. The conductive member may be a casing or liner disposed within the target wellbore for cased wellbores or the conductive member may be a pipe string, tool string, tubing, electrical wire or other conductive body disposed in the target well. Furthermore, this disclosure depicts only one target wellbore paired with one drilling well, but aspects of this disclosure can be applied to plurality of combinations of both. In other instances, well-known protocols, structures and techniques have not been shown in detail in order not to obfuscate the description.

Some embodiments include a multi-step real-time ranging to determine distance and direction between a drilling wellbore and an existing wellbore (the target wellbore) in a geological formation for drilling the drilling wellbore. The real-time ranging can be a passive ranging wherein an EM field is generated around the target wellbore through a power source located at the surface that runs a current down the casing of the target well. In a first step of the multi-step real-time ranging, a numerical simulation is conducted before initiating drilling of the drilling well. The numerical simulation can determine the predicted signal before the drilling wellbore is drilled. This numerical simulation can be used to create a model of the EM field distribution around the target wellbore that an EM sensor placed in the drilling rig down the drilling wellbore is expected to measure. A predicted signal can be the expected EM field signal measurements given certain depth and resistivity of the formation around the casing. The expected strength and direction of the EM field can be obtained from the expected signal. Guided by the predicted EM field signal at each depth and the measured EM field signal from the EM sensor, the drilling rig bores a drilling wellbore at a certain position respective to the target well. Often the position of the drilling wellbore with respect to the target wellbore would be parallel at a fixed distance. The minimum distance can be equal to a distance needed so that the wellbores would not collide given the range of error and uncertainty of the predicted EM field. Thus, the minimum distance between the target wellbore and the drilling wellbore depends on the accuracy of the predicted field signal.

Obtaining an accurate representation of the predicted EM signal in a target wellbore can be further exacerbated by ranging errors introduced by inaccurate formation data and surrounding noise. In passive ranging, the numerical simulation is based on legacy data such as the historical formation data and wellbore surveys. These legacy data may not be accurate and may cause errors in the predicted signal. Inherent noise exists in all wellbores and can also contribute to the inaccuracy of the predicted signals.

Thus, various embodiments include a multi-stage real-time ranging that results in more accurate EM ranging by incorporating real-time EM sensor measurements to improve a formation representation and to calibrate predicted signals. First stage involves creating a ranging model of the wellbore formation that the different wellbores (i.e. target wellbore, drilling wellbore, and other surrounding wellbores) and formation layers generated from legacy data. Legacy data includes data obtained during the different stages in the lifetime of the wellbore including surveying, planning, drilling, and operating stages of the target well. In some embodiments, this ranging model may further be used to create a simplified ranging model with a single homogeneous formation of an estimated average formation resistivity.

Second stage includes obtaining real-time magnetic field signal measurements (emitted from the target well) by a sensor positioned on a drill string that is used to drill the drilling wellbore. These real-time magnetic field signal measurements can then be used to calculate a more accurate ranging model and expected predict signal. In some embodiments, the second stage can include applying real-time background noise around the sensor to factor in the effect of noise. Noise measurement can be randomly imposed to the magnetic field generated in the ranging model. By incorporating the real-time background noise, the signal-to-noise ratio (SNR) of the ranging system can be obtained to better predict the accuracy of ranging measurements.

Various embodiments provide prediction of the ranging accuracy in real-time and better understanding of the ranging measurements at each location of the drilling well. The improved accuracy of the EM ranging reduces uncertainties and provides for increased hydrocarbon recovery. Various embodiments can further allow placing multiple wellbores in close proximity that may be advantageous in many drilling operations. For example, improvements in accuracy of ranging allows dense placement of wellbores that may reduce environmental impact, efficiently use available space in areas where there is a limited amount of available area for wellheads and improve drilling operations that use ranging.

<NUM> shows an example wellbore drilling system that uses real-time calibration of excitation ranging, according to some embodiments. In this example, the wellbore to be drilled is parallel to a target well. In other embodiments the drilling wellbore may not be in parallel, but at a predetermined distance apart from the target wellbore guided by real-time ranging, described herein. <NUM>, a wellbore drilling system <NUM> that uses real-time calibration of excitation ranging comprises a target wellbore <NUM> that extends from a target wellhead <NUM> into a subterranean formation <NUM> from the surface <NUM> of the formation. Inside at least a portion of the length of the target wellbore <NUM> is a conductive casing <NUM> where path for current flow is placed along the length of the target wellbore <NUM> and radiates a magnetic field radially outward all along the target wellbore <NUM>. In some embodiments, the target wellbore <NUM> may include a vertical section <NUM> and a directional section <NUM> where the directional section <NUM> is drilled from the vertical section <NUM> along a desired azimuthal path and a desired inclination path.

An electrical current 34a is provided to the target wellbore <NUM> by a power supply <NUM> at the surface <NUM> and is conveyed to the casing <NUM> of the target wellbore <NUM> through an insulated cable <NUM>. A portion of the electrical current 34a from the power supply <NUM> will leak into formation <NUM> as shown by current lines 34b but most of current 34a will travel along the casing <NUM> creating EM field <NUM> that emanates from along the length of the casing <NUM>. The power supply <NUM> is connected to a grounding well <NUM> by an insulated cable <NUM> to fulfill impedance criteria or ranging performance criteria. In some embodiments, the grounding wellbore <NUM> may be a grounding stake, and either may be further beneath the surface <NUM> into the subterranean formation <NUM>. The power supply <NUM> may control the voltage and current output from the power supply <NUM> to control the EM field <NUM> generated.

A drilling wellbore <NUM> is in the process of being drilled, where a drilling platform <NUM> is positioned over the subterranean formation <NUM> and controls the bottom-hole-assembly (BHA) <NUM> of the drilling rig through a conveyance <NUM> within the drilling wellbore <NUM>. The conveyance <NUM> may be tubing, a pipe string such as a drill string, or a cable, such as a wireline, slickline or the like, depending on the operation being conducted within the drilling wellbore <NUM> and is capable of telemetry to receive instructions and send measurements from the BHA <NUM>. The BHA <NUM> includes an EM sensor <NUM>, a drill bit <NUM>, a power supply <NUM>, a steering controller <NUM>, a controller <NUM>, and other instrumentation <NUM>. The EM sensor <NUM> can receive the EM field <NUM> signal measurements. The steering controller <NUM> enables the drilling wellbore <NUM> to be extended in a desired direction. Many suitable steering mechanisms such as steering vanes, "bent sub" assemblies, and rotary steerable systems may be used.

The drilling wellbore <NUM> can be drilled along a desired path <NUM> that is parallel to the wellbore or in another configuration conforming to the pre-well plan and can be guided by real-time calibration of excitation ranging. An interface <NUM> receives measurements from the EM sensor <NUM> and conveys the measurements to a computer <NUM> to perform the real-time calibration of excitation ranging. In some embodiments, the surface interface <NUM> and the computer <NUM> may perform various operations such as converting signals from one format to another, storing measurements, processing measurements, generating ranging models, and performing inversion methods. The computer <NUM> can include a processor <NUM> to perform these operations as wellbore as determining the distance and direction information from the EM field <NUM> measurements by the EM sensor <NUM>. The computer <NUM> also may include input devices such as keyboard, mouse, touchpad, etc. and output devices <NUM> such as a monitor, printer, etc. Such input device <NUM> and output device <NUM> provides a user interface that enables an operator to halt drilling, resume drilling, and update the desired path <NUM> to control the direction of drilling.

<FIG> depicts a flowchart of operations for real-time calibration of excitation ranging, according to some embodiments. Flowcharts <NUM> and <NUM> of <FIG> include operations that can be performed by hardware, software, firmware, or a combination thereof. For example, at least some of the operations can be performed by a processor executing program code or instructions. In some embodiments, such operations can be performed in a computer at the surface or downhole.

At block <NUM>, a ranging model of the target wellbore is generated. For example, with reference to FIG. <NUM>, a ranging model is generated for the target wellbore <NUM> to calculate the predicted EM field <NUM> signal, H<NUM>(MD), along the length of the casing <NUM> where MD refers to the measured depth of the subterranean formation <NUM>. The model can be generated using legacy resistivity profile data obtained during different stages in the lifetime of the wellbore including surveying, planning, drilling, and operating stages of the target well. With reference to FIG. <NUM>, the target wellbore <NUM> information such as resistivity profile data, current and voltage measurements from power supply <NUM> at the wellhead, and material properties of the target wellbore casing <NUM> can be used in a numerical method (either 1D or 3D) to simulate a ranging model. The ranging model can include the magnetic field H<NUM>(MD) signal expected to be received along the measured depth, MD, from which the ranging distance Dis<NUM>(MD) and direction Dir<NUM>(MD) can further be calculated from the magnetic field. Additionally, ranging accuracy can be determined by comparing the desired distance and direction. For example, FIG. <NUM> depicts an example ranging model of a sample wellbore system with multiple formation layers. In particular, FIG. <NUM> illustrates a ranging model <NUM> that is composed of various formation layers such as clay <NUM>, water <NUM>, shale <NUM>, sand <NUM>, reservoir <NUM>, etc. of various formation resistivities, Relay or water or shale, etc. The ranging model <NUM> includes surrounding wellbores <NUM> and <NUM>, a target wellbore <NUM> that is connected to a power supply <NUM>, and a ground stake or grounding wellbore <NUM> and a sensor <NUM> inside the drilling wellbore <NUM> that can detect the electromagnetic field <NUM> along the target well.

In some embodiments, this ranging model may further be transformed into a simplified ranging model with a single homogeneous formation layer with an estimated average formation resistivity, R<NUM>. To illustrate, FIG. <NUM> depicts an example simplified ranging model of a sample wellbore system with a single homogeneous formation layer of estimated average formation resistivity. In particular, FIG. <NUM> illustrates a simplified ranging model <NUM> that is composed of a single homogeneous formation layer <NUM> with an estimated average formation resistivity, R. The simplified ranging model <NUM> includes surrounding wellbores <NUM> and <NUM>, a target wellbore <NUM> that is connected to a power supply <NUM>, and a ground stake or grounding wellbore <NUM> and a sensor <NUM> inside the drilling wellbore <NUM> that can detect the electromagnetic field <NUM> along the target well.

At block <NUM>, a predicted signal along measured depths is calculated. The predicted signal can be calculated based on the generated ranging model. For example, with reference to FIG. <NUM>, either simplified or non-simplified models of the wellbore drilling system <NUM> may be used to calculates a predicted EM field <NUM> value, H<NUM>(MD), generated around the target wellbore casing <NUM> that would be received by the EM sensor <NUM> along the measured depth of the drilling well <NUM>.

At block <NUM>, the drilling wellbore is drilled to a measured depth MDN. With reference to FIG. <NUM>, the drilling is performed along a predetermined desired path <NUM> navigable using the EM sensor <NUM> and the EM field <NUM> generated around the casing <NUM>. Drilling may be stopped at any measured depth of logging point N, or MDN.

At block <NUM>, ranging measurements are taken. Measurements such as the EM field, H(MDN) can be taken by the EM sensor in real-time. For example, with reference to FIG. <NUM>, the EM sensor <NUM> attached to the BHA <NUM> or other parts of the conveyance <NUM> may be used to obtain the EM field <NUM> signal. This real-time data is then used to improve the accuracy of the predicted signal.

Different operations for calibrating the predicted signal are now described at blocks <NUM>, <NUM>, <NUM>, and <NUM>. One or more of these calibrations can be performed. For example, in some applications, the four different calibrations are performed on the predicted signal. In another example, only one of the calibrations are performed. In another example, any combination of two or three of these calibrations can be performed.

At block <NUM>, the predicted signal is calibrated by determining a scaling factor obtained with real-time signal measurements. For example, with reference to FIG. <NUM>, the equation for the scaling factor S, is given in Equation (<NUM>), where H(MDN) is the EM field <NUM> signal obtained by the EM sensor <NUM> at the measured depth, MD, of logging point N of the subterranean formation <NUM>. H<NUM>(MDN) is the predicted EM field signal at the measured depth of logging point N.

The scaling factor is applied to the ranging model data to calibrate the predicted signal at different measured depths. Applying the scaling factor can correct the predicted signal error at deeper depths more significantly than signal error at shallower depths.

At block <NUM>, the predicted signal is calibrated by tuning homogeneous formation resistivity obtained with real-time signal measurements. For example, with reference to FIG. <NUM>, the resistivity for simplified ranging model of the subterranean formation <NUM> is updated from R<NUM> to R<NUM> which in turn is used to make the real-time EM field <NUM> value, H(MDN), equal to the predicted magnetic field value, H<NUM>(MD), as shown below.

The difference between the real-time EM field signal and the predicted EM field signal can be attributed to inaccuracies in the resistivity of the ranging model and corrected to a new resistivity value of R<NUM>. Once R<NUM> is calculated, an updated predicted signal is obtained by recreating a ranging model with this new formation resistivity. For non-homogenized ranging models with multiple resistivity layers and resistivity values, the upper layer formation resistivity can be calibrated by assuming the same relationship given in Equation (<NUM>). Apart from the reservoir layer formation resistivity which cannot be calibrated, for other layers, the ranging model can be recreated and an updated predicted signal is generated at deeper depths.

At block <NUM>, predicted signal is calibrated by factoring in attenuation of EM waves obtained with real-time signal measurements. For example, with reference to FIG. <NUM>, the subterranean formation <NUM> resistivity values represented in the simplified ranging model by a homogeneous resistivity value is measured using two consecutive real-time measurements H(MDN-<NUM>) and H(MDN). The attenuation of the EM wave in conductive formation is related to the formation resistivity RN according to Equations (<NUM>) - (<NUM>), where ε is the permittivity, µ is the permeability, σ is the conductivity, and ω is the wave frequency. <MAT><MAT>.

In quasi-static regime where εω«σ, Equation (<NUM>) is reduced to the following.

Hence, the formation resistivity around MDN is shown by Equation (<NUM>)<MAT>.

By evaluating RN along measured depth in intervals, an updated resistivity profile is generated that is more accurate than the resistivity given in the legacy data-based profile. An updated predicted signal is obtained by recreating the ranging model with this new resistivity profile.

At block <NUM>, an updated predicted signal resistivity profile is generated using inversion method with real-time signal measurements. For non-homogenized ranging models, the predicted signal is calibrated by calibrating the formation resistivities through generating an updated resistivity profile using inversion method using real-time signal measurements obtained in block <NUM>. For example, with reference to FIG. <NUM>, an inversion engine takes in all measurements taken by the EM sensor <NUM> at previous logging points (H(MD<NUM>), H(MD<NUM>), H(MD<NUM>). H(MDN-<NUM>)) of the subterranean formation <NUM> to perform an inversion method and generates a more accurate ranging model of the wellbore drilling system <NUM>. The inversion method may include generating reduced dimension approximation models, formulating a constrained nonlinear optimization problem, transforming the inverted parameters, and performing Jacobian matrix calculation. The inversion method is able to generate an updated resistivity profile that can be used to recreate an updated ranging model.

At block <NUM>, background noise measurement is obtained. One or more noise measurements can be obtained through the EM field measurement with excitation on (where the power supply runs a current down the target wellbore) or with EM sensor measurement with excitation off (where the power supply would not run current down the target wellbore and thereby eliminate the EM field generated along the casing). For example, with reference to FIG. <NUM>, background noise can be obtained by the EM sensor <NUM> or obtained from the EM ranging measurements at block <NUM>. Thus, block <NUM> may be performed before blocks <NUM>, <NUM>, <NUM>, and <NUM> or be performed concurrently. Operations of the flowchart <NUM> continue at transition point A, which continues at transition point A of the flowchart <NUM>. From the transition point A of the flowchart <NUM>, operations continue at block <NUM>.

At block <NUM>, random signal noise is generated based on the background noise measurements. The random noise can be generated by using the recording of the background noise measurement. It can also be generated by generating uniform or Gaussian distribution noise with the nominal value of the background noise.

At block <NUM>, the random noise is added to calibrate the predicted signal. The predicted signal can be improved by adding a random noise signal to account for the effect that background noise would have on the predicted signal. The application of random noise updates the predicted signal which can be used to evaluate the signal-to-noise-ratio (SNR) of the ranging system. With reference to FIG. <NUM>, the SNR can help to improve the prediction of the accuracy of the ranging measurements taken by the EM sensor <NUM> along the drilling wellbore <NUM>. By accounting for the background noise that is inherent in subterranean formation <NUM>, the accuracy of the predicted signal can be increased.

<NUM> depicts an example magnetometer and line source arrangement which a synthetic test that adds noise to EM field measurements will utilize, according to some embodiments. <NUM> illustrates a sample magnetometer and line source arrangement <NUM> which a synthetic test that adds noise to EM field measurements will be based on. The magnetometer and line source arrangement <NUM> is composed of a drilling tool <NUM> with eight magnetometers <NUM> arranged azimuthally around the drilling tool <NUM>. Ranging distance <NUM>, voltage, electrical current <NUM> running through the line source <NUM>, and EM field <NUM> generated by the electrical current <NUM> are variable that may be controlled in the synthetic test for noise. By imposing random noise with specific amplitudes (i.e. -5pT, 0pT, 5pT, etc.) on the EM field <NUM>, the ranging errors is determined.

To illustrate, FIG. 7A-B depict sample graphs of a synthetic test that introduce random noise to magnetometer and line source arrangement with a distance value of five meters. 7A and 7B depict sample graphs <NUM> of a synthetic test that introduce random noise to the EM field <NUM> of FIG. <NUM> and the resulting ranging errors. In graphs <NUM>, ranging distance <NUM> is set to <NUM> meters (m), azimuthal angle to <NUM>°, and random noise amplitude to 5pT. Graphs in FIG. 7A depict errors related to distance that are introduced such as maximum distance error <NUM>, average distance error <NUM>, and standard deviation of distance error <NUM> on the measurements obtained by the eight magnetometers <NUM>. Graphs in FIG. 7B depict errors related to direction such as maximum direction error <NUM>, average direction error <NUM>, and standard deviation of direction error <NUM> on the measurements obtained by the eight magnetometers <NUM>. The x-axis of all of the graphs <NUM> is the EM field <NUM> (labeled in the graphs, H-field <NUM>) generated by the line source <NUM> in logarithmic scale <NUM>. The y-axis of graphs in FIG. 7A is the distance error <NUM> in percent and the y-axis of graphs in FIG. 7B is the direction error in percent <NUM>. Distance error lines <NUM> and direction error lines <NUM> describe the relationship between the error and the EM field <NUM> strength.

8A-8B depict sample graphs of a synthetic test that introduce random noise to magnetometer and line source arrangement with a distance value of <NUM> meters. 8A-8B illustrate sample graphs <NUM> of a synthetic test that introduce random noise similar to FIGS. 7A-7B but with a different distance value. In graphs <NUM>, ranging distance <NUM> is set to <NUM>, azimuthal angle to <NUM>°, and random noise amplitude to 5pT. Graphs in FIG. 8A depict errors related to distance that are introduced such as maximum distance error <NUM>, average distance error <NUM>, and standard deviation of distance error <NUM> on the measurements obtained by the eight magnetometers <NUM>. Graphs in FIG. 8B depict errors related to direction such as maximum direction error <NUM>, average direction error <NUM>, and standard deviation of direction error <NUM> on the measurements obtained by the eight magnetometers <NUM>. The x-axis of all of the graphs <NUM> is the EM field <NUM> (labeled in the graphs, H-field <NUM>) generated by the line source <NUM> in nT in logarithmic scale <NUM>. The y-axis of graphs in FIG. 8A is the distance error <NUM> in percent and the y-axis of graphs in FIG. 8B is the direction error in percent <NUM>. Distance error lines <NUM> and direction error lines <NUM> describe the relationship between the error and the EM field <NUM> strength.

In an alternate embodiment, background noise with different grounding or excitation levels than the predicted signal may be used to calibrate the predicted signal. The background noise used can be a random noise study, such as a Monte Carlo study, at a particular depth and can further be used to statistically evaluate the accuracy of the predicted signal. By using statistical analysis, the variations of the ranging distance and direction that was calculated based on the noise-injected EM field measurements can be evaluated and the accuracy of the ranging distance and direction at the measured depth be determined. To illustrate, FIG. <NUM> depicts sample graphs of calculated ranging distance and ranging direction with random noise injected into the ranging EM field measurement. <NUM> depicts sample graphs <NUM> of calculated ranging distance <NUM> and ranging direction <NUM> with random noise from a Monte Carlo study within ±5pT injected into the ranging EM field measurement. As the random noise index <NUM> increases, its effect is reflected by the changes in the ranging distance line <NUM> and ranging direction line <NUM>. By measuring the variations in these lines <NUM> and <NUM>, accuracy of the ranging distance and direction at a measured depth, MD, is determined.

Returning to the operations of the flowchart <NUM> of <FIG>, at block <NUM>, the predicted ranging distance and direction is calculated from the updated predicted signal. The predicted ranging distance Dis(MD) and direction Dir(MD) can be calculated from the updated magnetic field H(MDN) by decomposing the field into direction and magnitude.

At block <NUM>, the predicted ranging distance and direction is compared with desired ranging distance and direction to generate a ranging accuracy report at deeper depths. For example, the Dis(MD) and direction Dir(MD) determined at block <NUM> is compared to Dis<NUM>(MD) and direction Dir<NUM>(MD) obtained at block <NUM>. With reference to FIG. <NUM>, the ranging accuracy report can communicate a range of uncertainty of the predicted EM field and accuracy of the EM field <NUM> to be measured by the EM sensor <NUM> as it travels down deeper depths.

At block <NUM>, a determination is made of whether to continue drilling or to adjust ranging deployment. This determination can be made based on the ranging accuracy predicted at MDN. For example, with reference to FIG. <NUM>, if the decision to continue drilling or adjusting ranging deployment is made, the drilling wellbore <NUM> is taken further down the desired path <NUM> to the next measured depth and repeats the ranging calibration process. Furthermore, drilling conditions such as excitation or grounding may be adjusted based on this ranging. If the determination is made to continue drilling or adjusting ranging deployment, operations continue at transition point B, which continues at transition point B of the flowchart <NUM> (at block <NUM>). Otherwise, operations continue at block <NUM>.

At block <NUM>, drilling of the drilling wellbore is stopped or the adjusting the ranging deployment is stopped. The operations for real-time calibration of excitation ranging ceases. For example, with reference to FIG. <NUM>, the BHA <NUM> may continue to use the updated ranging model along with BHA <NUM> includes an EM sensor <NUM>, a drill bit <NUM>, a power supply <NUM>, a steering controller <NUM>, a controller <NUM>, and other instrumentation <NUM> to extend the drilling wellbore <NUM> in a desired path <NUM>, but no further adjustment of ranging deployment is made.

<NUM> depicts an example computer, according to some embodiments. A computer device <NUM> includes a processor <NUM> (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer device <NUM> includes a memory <NUM>. The memory <NUM> can be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer device <NUM> also includes a bus <NUM> and a network interface <NUM> (e.g., a Fiber Channel interface, an Ethernet interface, an internet small computer system interface, synchronous optical network (SONET) interface, wireless interface, etc.).

The computer device <NUM> includes a ranging signal processor <NUM> and ranging model generator <NUM>. In some cases, the computer device <NUM> also includes a wellbore system controller <NUM>. The ranging signal processor <NUM> calculates the predicted EM field signal and the resistivity of the subterranean formations. With reference to FIG. <NUM>, to calculate the predicted EM field signal and the formation resistivities, the ranging signal processor <NUM> can use legacy formation data, existing ranging models, electrical current and voltage data from the power supply <NUM>, and the EM sensor <NUM> data obtained real-time (including noise) from the BHA <NUM> of the drilling well <NUM>. The ranging signal processor <NUM> moreover can calculate the ranging distance and direction from predicted signal. The ranging model generator <NUM> can create a ranging model that simulates the various wellbore layout, formation layers and its resistivities, expected EM field signal, and the desired drilling wellbore path. The ranging model generator <NUM> can generate a ranging accuracy report at a measured depth as part of the ranging model in conjunction with the ranging signal processor <NUM>. The wellbore system controller <NUM> can also perform one or more operations for controlling a wellbore drilling system. For example, the wellbore system controller <NUM> can determine the voltage and current generated by the power supply into the target wellbore casing, modify the direction of drill bit, modify the speed of a drilling rig being lowered into a drilling well, control the EM sensor, etc. Any one of the previously described functionalities can be partially (or entirely) implemented in hardware and/or on the processor <NUM>. For example, the functionality can be implemented with an application specific integrated circuit, in logic implemented in the processor <NUM>, in a coprocessor on a peripheral device or card, etc. Further, realizations can include fewer or additional components not illustrated in Figure <NUM> (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor <NUM> and the network interface <NUM> are coupled to the bus <NUM>. Although illustrated as being coupled to the bus <NUM>, the memory <NUM> can be coupled to the processor <NUM>. The computer device <NUM> can be integrated into component(s) of the drilling rig downhole and/or be a separate device at the surface that is communicatively coupled to the coring tool for controlling and processing signals (as described herein).

Accordingly, aspects of the system, method or program code/instructions stored in one or more machine-readable media can take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that can all generally be referred to herein as a "circuit," "module" or "system. " The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc..

Any combination of one or more machine-readable medium(s) can be utilized. The machine-readable medium can be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium can be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine-readable storage medium would include the following: a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine-readable storage medium can be any tangible medium that can contain or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium.

A machine-readable signal medium can include a propagated data signal with machine readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal can take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A machine-readable signal medium can be any machine readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device.

Program code embodied on a machine-readable medium can be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing.

Computer program code for carrying out operations for aspects of the disclosure can be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language; and conventional procedural programming languages, such as the "C" programming language or similar programming languages. The program code can execute entirely on a stand-alone machine, can execute in a distributed manner across multiple machines, and can execute on one machine while providing results and or accepting input on another machine.

The program code/instructions can also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks.

Claim 1:
A method (<NUM>) comprising:
generating a ranging model of a ranging system (<NUM>) that includes a drilling wellbore to be drilled;
calculating a predicted electromagnetic field signal (<NUM>) along measured depths of the drilling wellbore based on the ranging model;
performing the following operations until the drilling wellbore has been drilled to a defined depth,
drilling, with a drill string, the drilling wellbore to an increment of the defined depth;
detecting, by a sensor positioned on the drill string, an electromagnetic field emanating from a target wellbore;
determining ranging measurements (<NUM>) to the target wellbore at the increment of the defined depth based on the electromagnetic field;
calibrating the predicted electromagnetic field signal for deeper depths based on the real time ranging measurements;
determining accuracy of the ranging measurements for deeper depths in the wellbore; and
modifying the drilling of the drilling wellbore or adjusting drilling operations based on the predicted accuracy of the ranging measurements for deeper depths.