Patent Description:
Wellbores drilled into subterranean formations may enable recovery of desirable fluids (e.g., hydrocarbons) using a number of different techniques. Knowing the location of a target wellbore may be important while drilling a second wellbore. For example, in the case of a target wellbore that may be blown out, the target wellbore may need to be intersected precisely by the second (or relief) wellbore in order to stop the blow out. Another application may be where a second wellbore may need to be drilled parallel to the target wellbore, for example, in a steam-assisted gravity drainage ("SAGD") operation, wherein the second wellbore may be an injection wellbore while the target wellbore may be a production wellbore. Yet another application may be where knowledge of the target wellbore's location may be needed to avoid collision during drilling of the second wellbore.

Electromagnetic induction tools disposed on bottom hole assemblies may be employed in subterranean operations to determine direction and distance between two wellbores. Electromagnetic induction tools may use different techniques to obtain current on a conductive member in the target wellbore. Approaches may include directly injecting a current into the conductive member and/or inducing a current on a conductive member by transmitting electromagnetic fields by coil antennas positioned in a second wellbore. The injection of current from the electromagnetic induction tools may induce a current along the bottom hole assembly, which may create a direct signal. The direct signal may be sensed and recorded by a receiver disposed in a second wellbore. Recording the direct signal may allow an operator to determine the position of the second wellbore in relation to the target wellbore.

<CIT> discloses a method of locating multiple wellbores including the following steps (a) exciting a first electrical current in a first wellbore, (b) exciting a second electrical current in a second wellbore, (c) disposing a ranging tool at a remote location with respect to the first and second wellbores, (d) receiving and detecting a magnetic field at the remote location with receivers provided on the ranging tool, and (e) measuring at least one wellbore parameter of each of the first wellbore and the second wellbore from the magnetic field received by the ranging tool.

These drawings illustrate certain aspects of some examples of the present disclosure, and should not be used to limit or define the disclosure.

This disclosure relates generally to an electromagnetic sensor system in wellbore operations, such as measuring-while-drilling (MWD), logging-while-drilling (LWD), wireline logging, and permanent monitoring operations. Specifically, this disclosure relates to the mitigation of undesired direct coupling between an electromagnetic source and a receiver in an electromagnetic sensor system. This coupling may be a result of conduction currents created on a metallic bottom hole assembly by the excitation of the electromagnetic source. In examples, tubulars may be disposed within the drill collar on a bottom hole assembly, a wireline tool mandrel, and/or permanently installed production casing. For brevity, the metallic tubular will be referred to as a bottom hole assembly below. The receiver in the electromagnetic sensor system may be a magnetometer and/or an induction coil, which may reside on the bottom hole assembly and/or outside. Similarly, where used, either electrode (source and return) may reside on the bottom hole assembly and/or outside, even on the surface. In certain types of electromagnetic sensor systems, electrical current may be injected into the formation via an electromagnetic source in the form of an electrode pair for logging, ranging, monitoring, and/or measurement purposes, among others.

<FIG> illustrates an electromagnetic sensor system <NUM>. Specifically, <FIG> shows an electromagnetic sensor system <NUM> for ranging. Electromagnetic sensor system <NUM> is disposed in a second production wellbore <NUM> that extends from a first wellhead <NUM> into a subterranean formation <NUM> from a surface <NUM>. <FIG> further illustrates first production wellbore <NUM>, which may extend from a second wellhead <NUM> into subterranean formation <NUM> from surface <NUM>. First production wellbore <NUM>, for example, may be an older production wellbore than second production wellbore <NUM>. Additionally, a first injection wellbore <NUM> may extend from a third wellhead <NUM> into subterranean formation <NUM> from surface <NUM>. First injection wellbore <NUM> may be an older injection well, for example, older with respect to new injector wells now being used. Generally, first production wellbore <NUM> and first injection wellbore <NUM> may include horizontal, vertical, slanted, curved, and other types of wellbore geometries and orientations. First production wellbore <NUM> and first injection wellbore <NUM> may be cased or uncased. In examples, a conductive member <NUM> may be disposed within first production wellbore <NUM> and first injection wellbore <NUM> and may comprise a metallic material that may be conductive and magnetic. By way of example, conductive member <NUM> may be a casing, liner, tubing, or other elongated steel tubular disposed in first production wellbore <NUM> and first injection wellbore <NUM>.

Determining the position and direction of second production wellbore <NUM> accurately and efficiently may be required in a variety of applications. Second production wellbore <NUM>, for example, may be a newer production well, for example, with respect to first production wellbore <NUM>. For example, second production wellbore <NUM> may be in drilling operations and it may be desired to avoid collision with first production wellbore <NUM> and first injection wellbore <NUM> in drilling operations. In examples, it may be desirable to drill second production wellbore <NUM> parallel to first production wellbore <NUM> and first injection wellbore <NUM>, for example, in SAGD applications. Alternatively, or additionally, first production wellbore <NUM> and first injection wellbore <NUM> may be may be a "blowout" well. First production wellbore <NUM> and first injection wellbore <NUM> may need to be intersected precisely by second production wellbore <NUM> in order to stop the "blowout. " In examples, electromagnetic sensor system <NUM> may be used for determining the location of second production wellbore <NUM> with respect to first production wellbore <NUM> and first injection wellbore <NUM>. It should be understood that the present techniques may also be applicable in offshore applications.

In further reference to <FIG>, a drill string <NUM> may begin at first wellhead <NUM> and traverse second production wellbore <NUM>. At or close to an end of drill string <NUM> may be a bottom hole assembly <NUM>. A drill bit <NUM> may be attached to a distal end of bottom hole assembly <NUM> and may be driven, for example, either by a downhole motor and/or via rotation of drill string <NUM> from surface <NUM>. While not illustrated, bottom hole assembly <NUM> may be conductive and may further comprise one or more of a mud motor, power module, steering module, telemetry subassembly, and/or other sensors and instrumentation as will be appreciated by those of ordinary skill in the art. As will be appreciated by those of ordinary skill in the art, bottom hole assembly <NUM> may be part of or include a measurement-while drilling (MWD) or logging-while-drilling (LWD) system.

As illustrated, electromagnetic sensor system <NUM> may comprise a plurality of sensors <NUM>. While <FIG> illustrates use of a plurality of sensors <NUM> on bottom hole assembly <NUM>, it should be understood that the plurality of sensors <NUM> may be alternatively used on a wireline or another downhole conveyance, e.g. slickline or coiled tubing. The plurality of sensors <NUM> may be used for determining the distance and direction to first production wellbore <NUM> and first injection wellbore <NUM>. Additionally, the plurality of sensors <NUM> may be connected to and/or controlled by information handling system <NUM>, which may be disposed on surface <NUM>.

Systems and methods of the present disclosure may be implemented, at least in part, with an information handling system. An information handling system may include any instrumentality or aggregate of instrumentalities operable to compute, estimate, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. The information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display. The information handling system may also include one or more buses operable to transmit communications between the various hardware components.

Alternatively, systems and methods of the present disclosure may be implemented, at least in part, with non-transitory computer-readable media. Non-transitory computer-readable media may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Non-transitory computer-readable media may include, for example, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.

In examples, information handling system <NUM> may communicate with the plurality of sensors <NUM> through a communication line (not illustrated) disposed in (or on) drill string <NUM>. In examples, wireless communication may be used to transmit information back and forth between information handling system <NUM> and the plurality of sensors <NUM>. Information handling system <NUM> may transmit information to the plurality of sensors <NUM> and may receive as well as process information recorded by the plurality of sensors <NUM>. In addition, the plurality of sensors <NUM> may include a downhole information handling system (not illustrated), which may also be disposed on bottom hole assembly <NUM>. Processing may be performed at surface with information handling system <NUM>, downhole with the downhole information handling system, or both at the surface and downhole. The downhole information handling system may include, but is not limited to, a microprocessor or other suitable circuitry, for estimating, receiving and processing signals received by the plurality of sensors <NUM>. The downhole information handling system may further include additional components, such as memory, input/output devices, interfaces, and the like. While not illustrated, the bottom hole assembly <NUM> may include one or more additional components, such as analog-to-digital converter, filter and amplifier, among others, that may be used to process the measurements of the plurality of sensors <NUM> before they may be transmitted to surface <NUM>. Alternatively, raw measurements from the plurality of sensors <NUM> may be transmitted to surface <NUM>.

Any suitable technique may be used for transmitting signals from bottom hole assembly <NUM> to surface <NUM>, including, but not limited to, wired pipe telemetry, mud-pulse telemetry, acoustic telemetry, and electromagnetic telemetry. While not illustrated, bottom hole assembly <NUM> may include a telemetry subassembly that may transmit telemetry data to the surface. An electromagnetic source in the telemetry subassembly may be operable to generate pressure pulses in the drilling fluid that propagate along the fluid stream to surface <NUM>. At surface <NUM>, pressure transducers (not shown) may convert the pressure signal into electrical signals for a digitizer <NUM>. Digitizer <NUM> may supply a digital form of the telemetry signals to information handling system <NUM> via a communication link <NUM>, which may be a wired or wireless link. The telemetry data may be analyzed and processed by information handling system <NUM>. For example, the telemetry data may be processed to determine location of second production wellbore <NUM> in relation to first production wellbore <NUM> and first injection wellbore <NUM>. Thus, a driller could control bottom hole assembly <NUM> while drilling second production wellbore <NUM> to intentionally intersect first production wellbore <NUM> and first injection wellbore <NUM>, avoid first production wellbore <NUM> and first injection wellbore <NUM>, and/or drill second production wellbore <NUM> in a path parallel to first production wellbore <NUM> and first injection wellbore <NUM>.

During ranging operations, a first source <NUM> may be attached to conductive member <NUM> disposed in first production wellbore <NUM>. First source <NUM> energizes conductive member <NUM>, which transmits a first magnetic field <NUM> into subterranean formation <NUM>. First magnetic field <NUM> may be transmitted at any number of frequencies, which are sensed and recorded by at least one of the plurality of sensors <NUM> disposed on bottom hole assembly <NUM>. A second source <NUM> is attached to conductive member <NUM> disposed in first injection wellbore <NUM>, which transmits a second magnetic field <NUM> into subterranean formation <NUM>. Second magnetic field <NUM> may be transmitted at any number of frequencies, which are sensed and recorded by at least one of the plurality of sensors <NUM> disposed on bottom hole assembly <NUM>. Measuring first magnetic field <NUM> and second magnetic field <NUM> may allow an operator to determine the distance and/or the location of electromagnetic sensor system <NUM> disposed in second production wellbore <NUM> from first production wellbore <NUM> and/or first injection wellbore <NUM>.

<FIG> illustrates a bird's eye view of <FIG> during a re-drill configuration <NUM>. It should be noted that a re-drill configuration may be defined as system and method for determining the location of a drilling operation to existing wellbores. For example, first injection <NUM> and first production wellbore <NUM> may have been drilled previously. Without limitations, first injection <NUM> may be any suitable vertical and/or horizontal well that may inject a fluid into a formation <NUM> (e.g., referring to <FIG>) to increase pressure in formation <NUM>. Without limitation, first production wellbore <NUM> may be any suitable vertical and/or horizontal well that may be used to recover fluids from formation <NUM>. In examples, second production wellbore <NUM> may be a drilling operation that may be in pre-drilling operations, drilling operations, or post-drilling operations. It should be noted that second production wellbore <NUM> may also be referred to and/or defined as a drilling operation. In examples, drilling operations, without limitation, may include drilling into formation <NUM> to create a producing well, injection well, and/or the like. As illustrated, R<NUM> is the distance from first injection <NUM> to second production wellbore206. Additionally, β<NUM> is the direction from second production wellbore <NUM> to first injection <NUM>. Furthermore, R<NUM> is the distance from first production wellbore <NUM> to second production wellbore206 and β<NUM> is the direction from second production wellbore <NUM> to first production wellbore <NUM>. During re-drilling operations, Htan and Hnor are recorded by sensor <NUM>. In examples, Htan is sensory measurements in the y direction and Hnor is sensory measurement in the x-direction. Both Htan and Hnor may include field contributions from both first injection <NUM> and first production wellbore <NUM>. Conventional magnetic ranging methods, illustrated in <FIG>, first injection <NUM> may be identified as a "target well. " A source <NUM>, which is a current source, is connected between the "target well" and a remote ground (or observation well) to excite current to flow along the "target well. " The current along the "target well" generates a magnetic field, which is measured and/or recorded by at least one sensor <NUM>. The at least one sensor may be disposed at and/or near second production wellbore <NUM>. However, current may leak out through a formation, which may be conductive, to first production wellbore <NUM>. This leakage may create an interference field, which may skew measurements and ultimately distance and direction from the "target well" to second production wellbore <NUM>. A new method of for determining distance and direction without an interference field may be beneficial.

<FIG> illustrates a method that may determine distance and direction without an interference field from the "target well" to second production wellbore <NUM>. Re-drill configuration <NUM> utilizes first injection <NUM> and first production <NUM> each as a "target well. " First injection <NUM> and first production <NUM> are energized and transmit a magnetic field into a formation that is measured and recorded by sensor <NUM> at second production wellbore <NUM>. This operation may be performed subsequently to take a survey at first injection <NUM> and first production <NUM>.

During operations, first injection <NUM> is excited by a first source <NUM>, which is a current source. Current I<NUM> may flow from first production <NUM>. Additionally, leakage current I<NUM> may leak out of first production <NUM>. Measurements of H fields, Htan and Hnor, are measured and recorded by sensors <NUM> at second production wellbore <NUM>. A second source <NUM>, which is a current source, excites first production <NUM>. It should be noted that first source <NUM> may excite both first injection <NUM> and first production <NUM> or second source <NUM> may excite both first injection <NUM> and first production <NUM>. Due to reciprocity of the two excitation configuration and similar properties of metal pipes, which may be disposed into the formation at first injection <NUM> and first production <NUM> as casing, current I<NUM> may flow from first production <NUM> and I<NUM> may leak out of first injection <NUM>. Measurements of H fields, Htan and Hnor, when second source <NUM> excites first production <NUM> are measured and recorded by sensors <NUM> at second production wellbore <NUM>.

In examples, first injection <NUM> and first production <NUM> have already been drilled, thus their relative position is known. Therefore, unknowns such as R<NUM> and β<NUM> may be eliminated by representing them as R<NUM> and β<NUM> which may increase accuracy of determining direction and distance from second production <NUM>. For example, if first injection <NUM> is located <NUM> miles (<NUM> kilometers) above first production <NUM>, the following equation may be used: <MAT> where <MAT>.

Therefore, there may be four equation with four unknowns (I<NUM>, I<NUM>, R<NUM>, β<NUM>)in the equation system seen in Table <NUM>.

Accuracy of this method may be seen below. In examples, a thinwire modeling code is used to model the response Htan and Hnor for re-drill configuration <NUM>, as illustrated in <FIG>. Three horizontal wells with <NUM> meter (<NUM>,<NUM> feet) depths may be modeled in the placement as in <FIG>. At a depth of <NUM> meters (<NUM>,<NUM> feet) a lateral section may be identified for measurements. The distance and direction results calculated with a convention method approach (<FIG>) and the results solved from Table <NUM> system (method from <FIG>) are compared in Table <NUM>. Different initial guesses have been tested in solving the Table <NUM> system. The solution is stable with a wide range of initial guesses.

In the above examples, in <FIG> and Table <NUM>, the tool face angle is assumed to be <NUM> degrees. During operations, when the tool face may be constantly changing during drilling operations, sensor <NUM> (e.g., referring to <FIG>) may have a blind spot for certain tool face angles. <FIG> shows and improved configuration with eight sensors <NUM> disposed azimuthally around a tool axis, which may be disposed in second production <NUM> during drilling operations. Each sensor may measure and record two measurements, Htan_i and Hnor_i A system for solving for distance and direction with eight sensors <NUM> may be found in Table <NUM>, seen below. For each excitation, one result matrix may be formed by calibrate the measurements of eight sensors <NUM> by a pre-calculated calibration matrix. The resulting matrix may contain four components: tangential H field, normal H-field, tangential gradient H field, and normal Gradient H-field. The gradient field may be obtained from sensor pairs at opposite azimuths. This larger equation system with more measurements may solve for accurate distance and direction for arbitrary tool face angles.

Both system in Table <NUM> and table <NUM> are nonlinear equation systems. The distance and direction may be solved or inverted by various optimization or inversion algorithms. The increase number of measurements and reduced number of unknowns proposed by the new multiple excitation method may help to promote the robustness and convergence of the inversion process. Solutions may also be less dependent on the initial guesses.

The thinwire modeling code may also used to model the response Htan and Hnor for the two-excitation multiple-sensor configuration in <FIG>. Three horizontal wells with <NUM> meters (<NUM>,<NUM> feet) depths are modeled as illustrated in <FIG> with various tool face angles along the lateral section depth between <NUM>-<NUM> (<NUM> feet to <NUM> feet). The distance and direction results calculated with the old single excitation approach and the results solved from Table <NUM> system are compared in <FIG> for multiple depths along the lateral section. It may be seen that the new method helps to greatly reduce the distance and direction errors compared to the old method. It provides stable results for different depths (tool face angles) with reasonable errors compared to the true distance and direction.

<FIG> illustrates an example where multiple excitation configurations may be deployed to further increase measurements and enhance solution accuracy. First injection <NUM> is excited by a source <NUM>, which is a current source, and first production <NUM> is excited by a source <NUM>, which is a current source. Additionally, a third source <NUM> may excite first injection <NUM> and first production <NUM>. Third source <NUM> may emit a similar current distribution along first injection <NUM> and first production <NUM> in opposite directions. The third excitation may add one more unknown I<NUM>, where I<NUM> is the current from third source <NUM> to first injection <NUM>. However, a plurality of sensors <NUM> disposed in second production <NUM> may measure and record additional measurements from third source <NUM>. Updating the inversion solution in Table <NUM> may help in determining the direction and distance from second production <NUM> to first injection <NUM> and first production <NUM>.

<FIG> shows a five excitation configuration. Besides excitations in <FIG>, more excitations may be deployed between first injection <NUM> and first production <NUM> and multiple sources, such as source <NUM>, source <NUM>, source <NUM>, source <NUM>, and/or source <NUM> (e.g., sources may be ground stakes, observation wells, and other nearby wells). Each source may add additional unknown currents to be measured and may be used in calculations. However, second production <NUM> may capture a plurality of measurements, which may be generated with a plurality of sensors <NUM>.

In examples, a new well may be drilled from an old wellhead (e.g., a step-out). In such examples, the old well (e.g., first injection <NUM> and/or first production <NUM>) may not be accessible in measurement operations. In such examples, an operator may not be able to deploy the reciprocal excitations with first injection <NUM> and first production <NUM> (i.e., <FIG>, <FIG>). However, as illustrated in <FIG>, an operator may employ a plurality of sources to generate more measurements. For example, source <NUM> and source <NUM> may excite first injection <NUM> at different times and different frequencies. This may generate a plurality of unknowns (different current from different sources) from measurements, however a plurality of measurements recorded by sensors <NUM> in second production <NUM>, which may assist in inversion measurements with distance and direction. Additionally, a plurality of surveys for each excitation with different tool faces may also increase measurements.

Systems described above may operate and/or function by any suitable method. <FIG> illustrates a flow chart <NUM> for determining a location of a second production wellbore. In step <NUM> an operator may excite a first production and/or a first injection with any number of sources. Sources may transmit current at any number of frequencies at any time interval. In examples, multiple sources, which may be attached at the first production and/or the first injection may transmit sequentially and/or simultaneously. In step <NUM> an operator may take multiple surveys by surface excitation with different first productions and/or first injections with different sources. In step <NUM>, an operator may reduce unknowns by using reciprocity of a twin excitation configurations (e.g., first injection and/or first production) and making use of prior first injection and producer surveys. In step <NUM>, an operator may employ multiple sensors to provide independent measurements, including gradient measurements. In step <NUM>, an operator may employ both normal and tangential measurements to provide more independent measurements. In step <NUM>, multiple surveys may be taken with different tool faces to further increase the number of measurements. In step <NUM>, measurements taken may be utilized to determine the location on a second production wellbore.

Claim 1:
A method for determining a position of a second production wellbore (<NUM>,<NUM>,<NUM>,<NUM>,<NUM>,<NUM>) comprising:
inducing a first current into a first conductive member (<NUM>) with a first source (<NUM>,<NUM>,<NUM>,<NUM>,<NUM>,<NUM>);
emitting a first magnetic field (<NUM>) generated by the first current from the first conductive member (<NUM>) into a formation (<NUM>);
inducing a second current into the first conductive member (<NUM>) with a second source (<NUM>,<NUM>);
emitting a second magnetic field (<NUM>) generated by the second current from the first conductive member (<NUM>) into the formation (<NUM>);
disposing an electromagnetic sensor system (<NUM>) into the second production wellbore (<NUM>,<NUM>,<NUM>,<NUM>,<NUM>,<NUM>), wherein the electromagnetic sensor system (<NUM>) comprises one or more sensors (<NUM>,<NUM>,<NUM>,<NUM>);
recording the first magnetic field with the one or more sensors (<NUM>,<NUM>,<NUM>,<NUM>) from the formation (<NUM>); and
recording the second magnetic field with the one or more sensors (<NUM>,<NUM>,<NUM>,<NUM>) from the formation (<NUM>).