SYSTEM AND METHOD FOR USING A RESISTIVITY TOOL WITH WIRED DRILL PIPE AND ONE OR MORE WELLS

Abstract

A resistivity tool is used with wired drill pipe and one or more wells. The resistivity tool has a transmitter, receiver modules located adjacent to the drill bit, and high sensitivity receiver modules located at greater distances from the drill bit relative to the receiver modules. The receiver modules and/or the high sensitivity receiver modules may also perform repeater functions for the wired drill pipe. The resistivity tool may provide information regarding a subsurface region of interest. The resistivity tool may be used in a system with sensors, and a distance between the sensors may be based on the type of measurement obtained by the sensors.

Description

BACKGROUND OF THE INVENTION

The present invention generally relates to a system and a method for using a resistivity tool with a telemetry system, such as wired drill pipe, in one or more wellbores. More specifically, the present invention relates to a resistivity tool having a transmitter, receiver modules located adjacent to the drill bit, and high sensitivity receiver modules located at distances from the drill bit relative greater than the receiver modules. The receiver modules and/or the high sensitivity receiver modules may also perform repeater functions for the wired drill pipe. The resistivity tool may provide information regarding a subsurface region of interest.

To obtain hydrocarbons, a drilling tool is driven into the ground surface to create a wellbore through which the hydrocarbons are extracted. Typically, a drill string is suspended within the wellbore. The drill string has a drill bit at a lower end of the drill string. The drill string extends from the surface to the drill bit. The drill string has a bottom hole assembly (BHA) located proximate to the drill bit.

Measurements of drilling conditions, such as, for example, an inclination and an azimuth, a drift of the drill bit, fluid flow rates and fluid composition, may be necessary for adjustment of operating parameters, such as, for example, a trajectory of the wellbore, flow rates, wellbore pressures, rate of penetration, weight on bit and the like. The BHA has tools that may generate and/or may obtain the measurements of the drilling conditions. For example, the BHA may acquire information regarding the wellbore and subsurface formations. Technology for transmitting information within a wellbore, known as telemetry technology, is used to transmit the information from the tools of the BHA to the surface for analysis. The information may be used to control the tools. Adjustment of the drilling operations in response to accurate real-time information regarding the tools, the wellbore, the formations and the drilling conditions may enable optimization of the drilling process to increase a rate of penetration of the drill bit, reduce a drilling time and/or optimize a placement of the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a drill string having a resistivity tool in an embodiment of the present invention.

FIG. 2 illustrates a drill string and a point of interest in a formation in an embodiment of the present invention.

FIG. 3 illustrates a box diagram of a drill string having repeaters positioned between a bottom hole assembly and a surface system or terminal in an embodiment of the present invention.

FIG. 4 illustrates a portion of a drill string with a transmitter module and a receiver module in an embodiment of the present invention.

FIG. 5 illustrates two wellbores where one of the wells substantially encircles a formation of interest in an embodiment of the present invention.

FIG. 6 illustrates two wellbores where one of the wellbores is positioned around a formation of interest in an embodiment of the present invention.

FIG. 7 illustrates areas of position uncertainty around two drilled wells in an embodiment of the present invention.

FIG. 8 illustrates a modular resistivity tool determining a position of a first well relative to a second well in an embodiment of the present invention.

FIG. 9 illustrates a modular resistivity tool used for avoiding collision between two wells in an embodiment of the present invention.

FIG. 10 illustrates a modular resistivity tool used for intercepting a first well with a second well in an embodiment of the present invention.

FIGS. 11A and 11B illustrate the effect of a cased well on the measurement of a modular resistivity tool in an embodiment of the present invention.

FIG. 12 illustrates a repeater having a receiver and a transmitter in an embodiment of the present invention.

FIG. 13 illustrates a repeater connected to a wired drill string in an embodiment of the present invention.

FIG. 14 illustrates different responses of sensors versus time or depth in an embodiment of the present invention.

FIG. 15 illustrates an optimum sensor-sensor spacing for different functions in an embodiment of the present invention.

FIG. 16 illustrates a drilling assembly with sensors spacing optimum for square root of time dependence in an embodiment of the present invention.

FIG. 17 illustrates a drilling assembly with sensors spacing optimum for linear time dependence in an embodiment of the present invention.

FIG. 18 illustrates the absolute and relative measurements in an embodiment of the present invention.

FIG. 19 illustrates the bottom hole assembly with one transmitter and two receiver modules that can be used for absolute and relative measurements in an embodiment of the present invention.

FIG. 20 illustrates a module with two tilted antennas in an embodiment of the present invention.

FIG. 21 illustrates the drilling assembly with high sensitivity receiver modules that can be used for absolute and relative measurements in an embodiment of the present invention.

FIG. 22 illustrates a module with tilted antennas for measuring +z and −z components of the signal in an embodiment of the present invention.

DETAILED DESCRIPTION OF THE PRESENTLY PREFERRED EMBODIMENTS

The invention is described with reference to figures that display embodiments of the invention. None of the drawings or description with reference to the figures is meant to limit the invention to these embodiments. The invention should be given its broadest interpretation and should only be limited by the claims.

The present invention generally relates to a system and a method for using a resistivity tool in conjunction with wired drill pipe. More specifically, the present invention relates to a resistivity tool having a transmitter module and a first receiver module located adjacent to the drill bit and a second receiver module located at a greater distance from the drill bit relative to the first receiver module. An acoustic impedance of a formation layer may be determined using the resistivity tool and the results may be used to improve drilling decisions or locate features not detectable by conventional resisitivity tools. The receiver modules may also perform repeater functions for the wired drill pipe. The resistivity tool may provide information regarding a subsurface region of interest. Sensors that obtain a measurement may be spaced from each other based on the dependence of the measurement on an independent variable.

Referring to FIG. 1, measurements may be provided by a bottom hole assembly 10 (hereafter “the BHA 10”) of a drill string 14 extending into a wellbore 30. The measurements may enable determination of the depths of boundaries separating adjacent subsurface formation layers. For example, the BHA 10 may comprise one or more tools measuring characteristics of the wellbore, the formation around the wellbore, and/or the drill string 20. For example, the BHA 10 may comprise one or a plurality of known types of telemetry, survey or measurement tools, such as, logging-while-drilling tools (hereinafter “LWD tools”), measuring-while-drilling tools (hereinafter “MWD tools”), near-bit tools, on-bit tools, and/or wireline configurable tools.

The LWD tools may include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment. Additionally, the LWD tools may include one or more of the following types of logging devices that measure formation characteristics: a resistivity measuring device; a directional resistivity measuring device; a sonic measuring device; a nuclear measuring device; a nuclear magnetic resonance measuring device; a pressure measuring device; a seismic measuring device; an imaging device; a formation sampling device; a natural gamma ray device; a density and photoelectric index device; a neutron porosity device; and the wellbore 30 caliper device.

The MWD tools may include one or more devices for measuring characteristics of the drill string 20, providing or generating power, providing communication to or from the BHA 10, measuring characteristics of the wellbore or formation surrounding the wellbore, such as measuring a direction or inclination of the wellbore, and other measurements known to those having ordinary skill in the art. For example, the MWD tools may include one or more of the following types of measuring devices: a weight-on-bit measuring device; a torque measuring device; a vibration measuring device; a shock measuring device; a stick slip measuring device; a direction measuring device; an inclination measuring device; a natural gamma ray device; a directional survey device; a tool face device; the wellbore 30 pressure device; and a temperature device.

The wireline configurable tool may be a tool commonly conveyed by wireline cable as known to one having ordinary skill in the art. For example, the wireline configurable tool may be a logging tool for sampling or measuring characteristics of the formation, such as gamma radiation measurements, nuclear measurements, density measurements, and porosity measurements.

The BHA 10 may also have a steering mechanism that may control a direction of drilling, the rotation of the drill string 14, an inclination of the wellbore and/or an azimuth of the wellbore. A structural model, known to one having ordinary skill in the art as a “layer cake model,” may be defined using the depths of the boundaries calculated using the electromagnetic LWD measurements. The LWD measurements may be resistivity measurements, density measurements and/or sonic velocity measurements, for example. The present invention is not limited to a specific embodiment of the electromagnetic LWD measurements, and the electromagnetic LWD measurements may be any measurements known to one having ordinary skill in the art.

Wired drill pipe 20 may be used to optimize determination of the depths of the boundaries. An example of the wired drill pipe 20 is described in U.S. Pat. No. 6,641,434 to Boyle et al. incorporated herein by reference in its entirety. The wired drill pipe 20 may consist of one or more wired drill pipe joints that may be interconnected to form at least a portion the drill string (hereinafter “wired drill string” or “wired drill pipe”). The wired drill pipe 20 may enable the BHA 10 to communicate with a surface terminal 5 in substantially real-time. The present invention is not limited to a specific embodiment of the wired drill pipe 20. In addition, other telemetry systems or combination of systems may enable the BHA 10 to communicate with the surface terminal 5 as known to one having ordinary skill in the art. For example, a combination of mud pulse telemetry and wired drill pipe may be used.

The surface terminal 5 may be, for example, a desktop computer, a laptop computer, a mobile cellular telephone, a personal digital assistant (“PDA”), a 4G mobile device, a 3G mobile device, a 2.5G mobile device, an internet protocol (hereinafter “IP”) video cellular telephone, an ALL-IP electronic device, a satellite radio receiver and/or the like. The surface terminal 5 may be located at a surface location and/or may be remote relative to the wellbore 30. The present invention is not limited to a specific embodiment of the surface terminal 5, and the surface terminal 5 may be any device that has a capability to communicate with the BHA 10 using the drill string 14. Any number of surface terminals may be connected to the drill string 14, and the present invention is not limited to a specific number of surface terminals.

The surface terminal 5 may store, process and analyze the data transmitted by the drill string 14. The surface terminal 5 may also generate and transmit control messages to the BHA 10 and/or other downhole tools. For example, the surface terminal 5 may automatically generate the control messages based on the data transmitted by the wired drill pipe 20. As a further example, the surface terminal 5 may provide the data to an operator that may consider the data and may transmit the control messages based on user input.

The wired drill pipe 20 may be used to optimize the determination of the depths of the boundaries by controlling configuration of tools associated with the BHA 10. For example, spacing and/or frequencies of the tools may be controlled to obtain optimum detection of the depths of the boundaries.

FIG. 2 depicts a resistivity tool 40 associated with a drill string 14 located within the wellbore 30. In the embodiment depicted in FIG. 2, the resistivity tool 40 has at least one transmitter module 55 and at least two receiver modules 51 and 52. In an embodiment, the resistivity tool 40 may have one or more dual purpose modules that may have a transmitter antenna and a receiver antenna. Thus, the dual purpose module may act as both a transmitter and a receiver.

The transmitter module 55 may have a transmitter antenna to transmit an electromagnetic signal into a formation F. The transmitter module 55 may have electronic circuitry to enable transmission of the electromagnetic signal from the antenna. The transmitter antenna may be a coil with a number of winding turns. The transmitter module 55 may be associated with the BHA 10 and/or may be located proximate to a drill bit 15 of the drill string 14. The transmitter module 55 may be programmed to transmit the electromagnetic signal as pulses at a predetermined sequence, such as, for example, a sequence of time intervals, time duration and/or frequency. In an alternate embodiment, the transmitter module 55 may be programmed from surface in real time using the wire drill pipe 20. The electromagnetic signal may include information about the formation F through which the electromagnetic signal has traveled before receipt by at least one of the receiver modules 51, 52. The electromagnetic signal may convey information about the transmitter module 55 and/or the receiver modules 51, 52, such as, for example, antenna efficiency, a distance between antennas, an antenna orientation and/or the like.

The receiver modules 51, 52 may receive the electromagnetic signal from the transmitter module 55. The receiver module 51 may be a first distance from a drill bit 15 and the receiver module 52 may be a second distance from the drill bit 15 which may be greater than the first distance. Each of the receiver modules 51 and 52 may have at least one receiver antenna that may be a coil having winding turns. In an embodiment, the receiver antenna of the receiver modules 51 and 52 may have more winding turns than the antenna of the transmitter module 55. Each of the receiver modules 51 and 52 may have electronic circuitry to enable the receiver antenna to receive the electromagnetic signal transmitted from the transmitter antenna.

One or more of the receiver modules 51 and 52 may be located within the BHA 10 at a distance from the transmitter module 55. The electromagnetic signal received by the receiver modules 51, 52, etc may be used to determine formation properties at a depth of investigation that may correspond to the distance from the receiver module to the transmitter module. The present invention may have any number of transmitter modules 55 and receiver modules 51, 52, and the present invention is should not be limited to a specific number of transmitter modules 55 or receiver modules 51, 52.

The resistivity tool 40 may comprise one or more receiver modules 61, 62 that are a greater distance from the transmitter module 55 than the receiver modules 51, 52. A person having ordinary skill in the art will appreciate that one or more of the receiver modules 51, 52, 61, 62 may be incorporated into the resistivity tool 40, and the present invention should not be limited to requiring all of the receiver modules 51, 52, 61, 62. The measurement between the transmitter module 55 and the receiver modules 61, 62 may have a deeper depth of investigation into the formation F. The signal level may be lower for the receiver modules 61, 62 than the receiver modules 51, 52. For example, the receiver modules 61, 62 may measure weaker electromagnetic signals encountered at relatively long distances from the transmitter module 55, or at least distances great than those measured by the receiver modules 51, 52.

The antennas on the receiver modules 61, 62 may be wound to cause higher sensitivity. For example, the receiver modules 61, 62 may have a high sensitivity receiver antenna (hereinafter “HSR antenna”) comprising a coil with more winding turns than the receiver antenna for the receiver modules 51, 52. In light of receiver modules 61, 62 being farther away from the transmitter module 55, the receivers 51, 52 may be referred to as the near receivers.

One or more joints of wired drill pipe 20 may be positioned between and connect the receiver modules 61, 62 and the BHA 10. As shown in FIG. 3, the wired drill pipe 20 may have repeaters 100 for amplifying telemetry signals transmitted by the wired drill pipe 20 as discussed in more detail hereafter. One or more of the transmitter modules 55 and the receiver modules 51, 52, 61, 62 may function as the repeaters 100 for the wired drill pipe 20 and/or may be incorporated into the repeaters 100. For example, one of the receiver modules 51, 52, 61, 62 may be positioned in the same drill collar as one of the repeaters 100. The repeaters 100 of the wired drill pipe 20 may be located at intervals between the drill bit 15 and Earth's surface. Thus, the receiver modules 51, 52, 61, 62 may amplify the telemetry signals transmitted by the wired drill pipe 20 (the repeater function), and receive the electromagnetic signals transmitted from the transmitter module 55 (the receiver function). The receiver modules 51, 52, 61, 62 may have power available to support the electronic circuitry for both functions. In an embodiment, the transmitter module 55 may function as one of the repeaters 100.

The transmitter antenna, the receiver antenna and/or the HSR antennas may be wound along an axis of the resistivity tool 40 (z axis) to create a dipole moment along the tool axis. The dipole moment may be transverse to the axis of the resistivity tool 40, such as, for example, at an x direction or a y direction, or, alternatively, the dipole moment may be tilted relative to the axis of the resistivity tool 40, such as, for example, at an x-z direction or a y-z direction.

The resistivity tool 40 may be operated at or within a range of predetermined frequencies, such as frequencies from approximately one kHz to approximately two MHz. If the receiver modules 61, 62 are distant from the BHA 10, the receiver modules 61, 62 may be operated at frequencies in the lower portion of the predetermined ranges, such as in the lower range of about one kHz to two MHz range or may even be operated at frequencies below 1 kHz. In an embodiment, the receiver modules 61, 62 distant from the BHA 10 may be operated at frequencies approximately equal to one kHz or less than one kHz. As the distance between the transmitter module 55 and the receiver modules 51, 52, 61, 62 increase, a lower frequency of operation may compensate for signal loss in the formation F.

Referring again to FIG. 2, the wired drill pipe 20 may provide synchronization and/or data transfer between the BHA 10 and the receiver modules 51, 52, 61, 62. The transmitter module 55 and the receiver modules 51, 52, 61, may be synchronized by sending a trigger pulse, for example, from the transmitter module 55 to the receiver modules 51, 52, 61, 62. The trigger pulse may be sent at a time prior to sending the electromagnetic signal to prepare the electronic circuitry of the receiver modules 51, 52, 61, 62 to detect the electromagnetic signal. The time that the trigger pulse may be sent may be adjusted based on time elapsed during generation of the trigger pulse by the transmitter module 55, a time elapsed during travel of the trigger pulse to the farthest away one of the receiver modules 51, 52, 61, 62, and processing time of the receiver modules 51, 52, 61, 62. The time elapsed during travel of the trigger pulse to the receiver modules 51, 52, 61, 62 may depend on the distance between the transmitter module 55 and the receiver modules 51, 52, 61, 62.

The transmitter module 55 and the receiver modules 51, 52, 61, 62 may have internal clocks that may drift relative to each other. For example, a time indicated by the clock of one of the receiver modules 51, 52, 61, 62 at a specific time may not match a time indicated by the clock of the transmitter module 55 at that specific time. The drift may depend on time of use and temperature encountered. The drift may cause association of inaccurate time information with the data obtained by the receiver modules 51, 52, 61, 62. Messages transmitted between the transmitter module 55 and the receiver modules 51, 52, 61, 62 using the wired drill pipe 20 may be used for synchronization of the clocks.

Synchronization may be periodic such that the transmitter module 55 and the receiver modules 51, 52, 61, synchronize at predetermined time intervals. A time interval for synchronization may be based on the drift. For example, the time interval may be one second if the drift is relatively high. As a further example, the time interval may be one hour if the drift may be relatively low.

The messages used for synchronization may be “ping” messages. As known to one having ordinary skill in the art, a “ping” message may be a message that requests a recipient device for a response. Receipt of the response by the device that sent the “ping” message may enable calculation of a round-trip transmission time. A sending device of the transmitter module 55 and the receiver modules 51, 52, 61, 62 may use the wired drill pipe 20 to transmit the messages for synchronization to the other devices. The messages may indicate a time provided by the clock of the sending device and/or the round-trip transmission time. The transmitter module 55 and the receiver modules 51, 52, 61, 62 may use the messages to determine a rate of drift. The rate of drift may be used to synchronize the clocks in the absence of the messages, such as, for example, if communication using the wired drill pipe 20 is interrupted.

A processor may be located in and/or in communication with the transmitter module 55 and the receiver modules 51, 52, 61, 62. The processor may receive the data from the transmitter module 55 and the receiver modules 51, 52, 61, for processing. The surface terminal 5 may receive and/or process the data. The wired drill pipe 20 may transmit the data between the transmitter module 55, the receiver modules 51, 52, 61, 62 and/or the surface terminal 5.

FIG. 2 depicts a portion of the formation F having a first layer 201, a second layer 202, a third layer 203, a fourth layer 204, a fifth layer 205, a sixth layer 206 and/or a seventh layer 207. The wellbore 30 may be drilled in the formation F through the first layer 201, the second layer 202, the third layer 203 and the fourth layer 204. The wellbore 30 may land in the fifth layer 205 and continue through the fifth layer 205 as a horizontal well.

The resistivity tool 40 may obtain measurements that may be used to determine a formation model. The formation model may have formation properties and/or boundary locations of adjacent layers. The formation layer model may be used to make drilling decisions such as geosteering, landing, etc. For example, the BHA 10 may obtain measurements regarding the properties of the third layer 203, the fourth layer 204, the fifth layer 205, the sixth layer 206 and/or the seventh layer 207 (hereinafter “the properties of the third layer through the seventh layer 203-207”), but the first layer 201 and/or the second layer 202 may be beyond the depth of investigation of the BHA 10. However, the BHA 10 may or may not be able to obtain measurements regarding the properties of the first layer 201 and/or the second layer 202 during horizontal drilling in the fifth layer 205. The receiver module 61 may be positioned in or adjacent to the fourth layer 204 at the time the drill string 14 is depicted in FIG. 2. Assuming the properties of the first layer 201 and/or the second layer 202 do not change, the previously obtained measurements regarding the properties of the first layer 201 and/or the second layer 202 and the measurements regarding the properties of the third layer through the seventh layer 203-207 may be used in a forward model to calculate expected data for one or both of the receiver module 61, 62.

An electromagnetic signal transmitted from the transmitter module 55 and received by the receiver modules 61, 62 may be used to compare with the forward model results. The processor and/or the surface terminal 5 may compare the data based on the electromagnetic signal with the expected data. Comparison of the data based on the electromagnetic signal with the expected data may indicate if the formation model may be accurate. For example, comparison of the data based on the electromagnetic signal with the expected data may indicate if the formation properties and/or the boundary locations of adjacent layers of the formation model have changed.

In the scenario depicted in FIG. 1, the measured and modeled values are expected to agree within the noise level. The scenario depicted in FIG. 2 is similar to the geometry of FIG. 1. However, a region of interest 150 may be located in the second layer 202. The region of interest 150 may be located at a distance from the wellbore 30 that prevented detection when the BHA 10 was located in the first layer 201, the second layer 202, the third layer 203 and/or the fourth layer 204. For example, the region of interest 150 may be a salt dome. The present invention is not limited to a specific embodiment of the region of interest 150, and the region of interest 150 may be any subsurface region.

The receiver modules 61, 62 may have sufficient depth of investigation to detect the region of interest 150. The data based on the electromagnetic signal received by the receiver modules 61, 62 may differ from the expected data. The difference between the data based on the electromagnetic signal and the expected data may indicate that the formation may have a feature not considered in the formation model. The data based on the electromagnetic signal may be used to determine properties of the region of interest 150, such as, for example, a location or the shape and dimensions of the region of interest 150.

Sensitivity of the electromagnetic signal to the region of interest 150 may depend on the distance from the transmitter module 55 to the receiver modules 51, 52, 61, 62. The sensitivity of the electromagnetic signal to the region of interest 150 is not a single event. As drilling moves the BHA 10, the distance from the transmitter module 55 to the receiver modules 51, 52, 61, 62 may change. For example, comparing FIG. 2 with FIG. 4, in FIG. 4 the receiver module 61 has moved into the horizontal section of the well as a result of further drilling and the distance between the transmitter module 55 and the receiver module 61 has increased compared to the embodiment of FIG. 2. The embodiment of FIG. 4 may have a larger depth of investigation. This increase in depth of investigation favors the detection of region of interest 150. This example demonstrates how the distance between the transmitter antenna and the receiver antenna changes by the curvature in the drill assembly and is typically at its maximum when the curvature changes to a straight section. The data based on the electromagnetic signal received by the receiver modules 61, 62 in the scenario of FIG. 4 may be used to determine the properties of the region of interest 150, such as, for example, the location of the region of interest 150.

The resistivity tool 40 may be used for other applications in drilling environment. For example FIG. 5 depicts a situation in which a first well 301 has encountered the region of interest 150. The region of interest 150 may be any subsurface region. A cylinder 305 located around the first well 301 may represent a radius of the depth of investigation of the resisitivity tool 40 as described previously. Typically, the cylinder 305 may cover a relatively small portion of the region of interest 150 as the geological features are usually large. The drill string 14 may be only capable of measuring properties of the portion of the region of interest 150 that may be located within the cylinder 305. The properties of the portion of the region of interest 150 that may be located within the cylinder 305 may not provide detailed information about the region of interest 150, such as, for example, a shape of the region of interest 150, a size of the region of interest 150 and/or the like.

A second well 302 that may be located adjacent to and/or extend through the region of interest 150 may provide the detailed information about the region of interest 150. As generally shown in FIG. 5, the second well 302 may encircle the region of interest 150 and/or may enable determination of the detailed information about the region of interest 150. The first well 301 and the second well 302 may not be located in the same plane. The present invention is not limited to a specific embodiment or a specific location of the first well 301 or the second well 302.

For example, the second well 302 may have a different trajectory relative to the first well 301. FIG. 6 generally illustrates that the second well 302 may be a side track well that may originate from the first well 301. Alternatively, the second well 302 may be drilled independently from the first well 301. The second well 302 may be used for other purposes, such as, for example, as a monitoring well, a secondary producer well, an injection well and/or the like.

The second well 302 may be drilled to maintain a distance from the region of interest 150. The distance of the second well 302 from the region of interest may be maintained by using the resistivity tool 40 within the second well 302. Alternatively, other well placement devices, such as, for example, sonic or fluid typing tools may be used to maintain the distance of the second well 302 from the region of interest 150 but it is desirable to have as large a depth of investigation as possible and that is provided by the ultra deep resisitivity tool 40.

The trajectory of the second well 302 may provide the detailed information about the region of interest 150, such as, for example, the shape of the region of interest 150, the size of the region of interest 150 and/or the like. Measurements obtained by tools within the second well 302 may provide properties of the region of interest 150 from a location closer to the region of interest 150 relative to the first well 301. The properties of the region of interest 150 determined by the second well 302 may be compared with properties of the region of interest 150 determined by the first well 301 to assess possible variation of the properties. For example, a water cone may be located adjacent to a pre-existing well, and drilling a second well may provide information regarding the water cone. As a further example, one or more side track wells may be drilled to obtain other information, and the resistivity tool 40 may be used in the side track wells to increase the accuracy of the estimated position of the first well 301 and/or the second well 302 relative to the reference point 310 and/or each other. In addition, the resistivity tool 40 may be used in the side track wells to obtain the detailed information regarding the region of interest 150.

Another application of this invention is for measuring the distance between two wells. As generally shown in FIG. 7, a position of the first well 301 and/or a second well 302 relative to a reference point 310 may be monitored. For example, the reference point 310 may be located at the surface, such as, at a top of the drill string 14 on the rig floor. The present invention is not limited to a specific embodiment of the reference point 310. As drilling proceeds, the position of the first well 301 and/or the second well 302 relative to the reference point 310 may be estimated using data obtained during the drilling. Inaccuracy in the estimated position of the first well 301 and/or the second well 302 relative to the reference point 310 may increase as a depth of the first well 301 and/or the second well 302 increases. For example, the uncertainty in the position of the first well 301 is represented by 301a and the uncertainty of the second well is generally represented by 302a. A distance D is illustrated in FIG. 7 to show the actual distance between the first well 301 and the second well 302. The distance D may be less than the uncertainty 302a of the second well 302 and/or less than the uncertainty 301a of the first well 301.

The resistivity tool 40 may have a flexible architecture, stemming from adjustable inter module spacing and programmable frequency of operation. These features allow a user to optimize the architecture for optimum signal level and/or depths of investigation. Often, it is desired to drill a second well in the vicinity of an existing cased well. In such a case, there may be three desired objectives in such operation, namely a) to drill the second well such that it intersects the existing well (interception), b) to drill the second well such that it avoids the existing well (collision avoidance), and c) drill the second well such that it follows the existing well within some distance (tracking). FIG. 8 shows a tracking scenario where a cased well 800 already exists and the second well 302 is being drilled at a desired distance from the first. FIG. 9 shows a collision avoidance scenario where the trajectory of the second well 302 is changed to avoid collision with the cased well 800. Similarly, FIG. 10 shows an interception scenario where the trajectory of the second well 302 is adjusted to ensure the two wells 302, 800 meet.

The presence of casings in the cased well 800 may be an advantage for resistivity methods. This is due to the high conductivity of the metallic casings and their high magnetic permeability. The high conductivity of casing compared with the background formation, causes strong conductivity contrast with the background and aids in detecting the presence of the casing. In addition, formation's lack of magnetic permeability coupled with relatively large magnetic permeability of casing material creates strong magnetic permeability contrast which is useful for resistivity and magnetic ranging. The resistivity tool 40 utilizes these advantages to achieve at least the three objectives identified above.

Measurement of positions of the first well 301 and the second well 302 relative to each other may increase accuracy of the estimated position of the first well 301 and/or the estimated position of the second well 302 relative to the reference point 310. Increasing the accuracy of the estimated position of the first well 301 and/or the estimated position of the second well 302 may increase accuracy of determination of a position of the region of interest 150. The trajectory of the second well 302 may not be pre-determined and/or may be adjusted during drilling based on the measurements obtained during drilling. For example, the second well 302 may be moved to a different plane based on the information regarding the region of interest 150.

During drilling of the second well 302, the measurements obtained by tools having a shallower depth of investigation, such as, for example, the receiver modules 50 located in the BHA 10, may be used to steer the second well 302. The receiver modules 51, 52, 61, 62 located in the BHA 10 may enable determination of distances between the second well 302 and the region of interest 150 more accurately relative to tools having a larger depth of investigation. The receiver modules 51, 52, 61, 62 may be used to determine the positions of the first well 301 and the second well 302 relative to each other. For example, the receiver modules 51, 52, 61, 62 may enable determination of the positions of the first well 301 and the second well 302 relative to each other after the first well 301 has received casing. The receiver modules 51, 52, 61, 62 may determine a distance from a point located on the first well 301 and a point located on the second well 302. Alternatively, a magnetic ranging device may be used to determine the positions of the first well 301 and the second well 302 relative to each other, such as, for example, the magnetic ranging device disclosed in U.S. Patent App. Pub. No. 2008/0041626 to Clarke, herein incorporated by reference in its entirety.

Assume the z-axis to be along the axial tool direction. The transmitter and receiver antennas may be tilted at 45 degree relative to the tool axis however, the method of this invention is not limited to tilted antennas transverse or axial or some combination of these antennas can also be used. In addition, the tilted antennas may have a tilt angle different from 45 degree. The voltage measured by the receiver antennas is a function of the coupling tensor the components of which can be extracted using the methods well known in the art. Some of these components such as (zz), and (xx)+(yy) are non-directional. However, the off diagonal elements of the tensor are directional and can be used to determine the azimuthal distribution of resistivity. The azimuthal distribution of resistivity coupled with relatively deep depth of investigation can be used to detect the presence of casing and achieve tracking, avoidance or interception.

Assuming the casing is within the depth of investigation of the resistivity tool 40, some components of the coupling tensor will be highly affected by the presence of casing. For example, if the resistivity tool 40 and the casing are roughly parallel (the tracking case mentioned above) and are contained in the plane defined by x and z coordinates, the couplings (xx), (yy), (xz), and (zx) may be strongly affected. If the resistivity tool 40 is aligned along z and the casing is aligned along y, then (zz), (zx), (xz), and (xx) couplings may show strong response. Similarly if the casing is along x instead of y, the components of interest will be (zz), (zy), (yz), and (yy). Having mentioned the two extreme cases of parallel and perpendicular orientations, most situations will likely be between these two limits and thus all components of the coupling tensor come into play. In these cases, it will be possible to extract information about the casing in particular its relative position and orientation.

FIG. 11a shows a magnetic dipole 700 as generated by one of the coils in transmitter module 55. For FIG. 11A, the dipole 700 is oriented normal to the plane. Excitation of the dipole 700 leads to Eddy currents 702 circulating in the background formation. If the dipole 700 is close to a metal casing 704, as shown in FIG. 11B, the high conductivity of the casing 704 causes the Eddy currents 702 to change shape and flow through the casing 704. Comparing FIGS. 11A and 11B, the shape change of the Eddy currents 702 can be approximated by the presence of a reactive current loop 706 as shown in FIG. 11B. The effect of casing 704 is then equivalent to the magnetic field created by the reactive current loop 706, and the signal measured by a receiver is the superposition of the magnetic field from FIG. 11A and the field from the reactive current loop 706 of FIG. 11B. To detect the casing 704 one needs to separate the two magnetic fields and the use of relatively low frequencies of operation (those below 10 kHz) may aid or improve the process.

An inversion technique such as Bayesian or an iterative minimization can be used to extract the casing information from the received data or from the coupling tensor. The inversion will solve for a set of parameters describing the formation (layer boundary positions and orientations, resistivities of layer, etc) and a set of parameters describing the casing (relative location, relative orientation, magnetic permeability, cross-section, conductivity, etc).

The wired drill pipe 20 located between the transmitter module 55 and the receiver modules 51, 52, 61, 62 aids in the measurement stage when the transmitter and receiver antennas need to communicate data and timing information. In addition, the high-speed telemetry provided by wired drill pipe 20 allows measurements to be conducted at higher sampling rate and the large volume of the data to be sent to surface. A processor located at the surface, such as the surface terminal 5, uses the data and delivers real-time geometrical information about relative position between the existing well trajectory and nearby casing allowing real time steering decisions to be made and implemented. The high sampling rate is essential in determining the casing information with high definition which may be needed to achieve casing tracking, interception, or avoid collision. The success of this method is due to a) high definition structural information about the casing, b) the deep depth of investigation of the resistivity tool 40 to provide maneuverings time, and c) availability of the high data rate to allow real time trajectory adjustment decisions and implementation of these decisions.

As generally shown in FIG. 3, the wired drill pipe 20 may have the repeaters 100 that may facilitate obtaining measurements at various points in the wellbore 30. Time-lapsed measurements may be taken using repeated measurements from different sections of the drill string 14. The drill string 14 may have a distance between the repeaters 100, such as, for example, approximately fifteen hundred feet. The distance between the repeaters 100 may be adjusted to a desired distance. As each of the repeaters 100 passes by a specific point in the wellbore, the repeaters 100 may obtain measurements for a region adjacent to the specific point in the wellbore. For example, if the repeaters 100 are spaced three thousand feet apart and an average rate of penetration is ten feet per minute, approximately one of the repeaters 100 may pass by a specific point in the wellbore every five hours. Thus, the repeaters 100 may provide a timed view of wellbore conditions, so that conditions such as, for example, washout, invasion and/or the like, may be observed as the conditions develop and/or corrective actions may be taken. Corrective actions may be, for example, moving the tool to a different position, changing drilling fluid rates, changing drilling fluid characteristics, using a tool to change pressure in various parts of the wellbore, circulating specific chemicals to a controlled region and/or the like. The present invention is not limited to a specific embodiment of the conditions or the corrective actions.

As illustrated in FIG. 12, each of the repeaters 100 may have a transmitter 110 and/or one or more receivers 120 at varying distances from the transmitter 110. The varying distances of the receivers 120 may enable different depths of investigation to be used. As illustrated in FIG. 13, one or more additional receivers 121 may be located at a distance from the transmitter 110 that may be greater than the distance between the receiver 120 and the transmitter 110. For example, the additional receiver 121 may be located ninety feet or more from the transmitter 110. The additional receiver 121 may enable the electromagnetic signal transmitted from the transmitter 110 to travel further into the wellbore for a deeper depth of investigation.

Any number of additional receivers 110 may be employed, and the additional receiver 121 may be located at any distance from the transmitter 110. For example, the additional receivers 121 may be located at twenty feet, thirty feet, sixty feet, ninety feet and one hundred feet from the transmitter 110. The additional receiver 121 may be located adjacent to the repeaters 100. The additional receiver 121 may be located adjacent to the BHA 10. Each of the repeaters 100 may be housed in a section 21 of the wired drill pipe 20 that may have connectors 22 for attachment to adjacent sections 21 of the wired drill pipe 20. The additional receivers 121 may be located in different sections 21 of the wired drill pipe 20 relative to the transmitter 110 that may transmit the electromagnetic signal to the additional receiver 121.

The surface terminal 5 connected to the wired drill pipe 20 may display the information obtained by the BHA 10, the receiver 120 and/or the additional receiver 121. As discussed previously, the surface terminal 5 may transmit control messages based on the information. For example, the control messages may vary the depth of investigation at various points of the drill string 14. The surface terminal 5 may transmit the control messages at predetermined time intervals. The surface terminal 5 may transmit the control messages using the wired drill pipe 20. The control messages may adjust the depth of investigation for each of the transmitters 110, the receivers 120 and/or the additional receivers 121.

For example, the surface terminal 5 may direct the additional receiver 121 that may be located a predetermined distance from a specific one of the repeaters 100 to begin recording data and/or may direct the transmitter 110 associated with the specific repeater 100 that a predetermined depth of investigation is desired. In response, the transmitter 110 may adjust a frequency of the electromagnetic signal transmitted to correspond to the predetermined depth of investigation. The transmitter 110 may adjust other parameters to correspond to the predetermined depth of investigation. Thus, the surface terminal 5 may control gathering of specific information at various locations precisely when the specific information may be required.

As discussed previously, the repeaters 100 may amplify the signals transmitted by the wired drill pipe 20. The repeaters 100 may be modules located between sections of the wired drill pipe 20 that may receive the signal, may amplify the signal and may broadcast an amplified signal. The repeaters 100 may increase transmission range of the signal. Each of the repeaters 100 may have electronic circuitry and/or a power source. The power source may, for example, be a battery, turbine or power harvesting mechanism. Availability of power from the power source of the repeaters 100 may enable association of sensors with the repeaters 100. Thus, the repeaters 100 may perform both repeater functions and measurement functions. The sensors may be used for applications other than telemetry amplification.

Alternatively, the sensors may be connected to the drill string 14 by inserting the sensors between sections of the wired drill pipe 20 similar to how the repeaters 100 are attached to the wired drill pipe 20. The sensors may be designed to provide repeater functions. Thus, the sensors may perform both repeater functions and measurement functions. Whether the repeaters 100 are designed to have measurement functions or the sensors are designed to have repeater functions, dual purpose modules may distribute the sensors along the length of the drill string 14.

The sensors distributed along the length of the drill string 14 may travel downward at a rate equal to or greater than the rate of penetration as the drilling occurs. Alternatively, during removal of the drill string 14 from the wellbore, the sensors distributed along the length of the drill string 14 may travel upward at a rate. Thus, the position of the sensors may be time dependent. The distribution of the sensors may depend on the nature of the physical phenomenon being interrogated by the sensor, the rate of travel and/or a required repeater distance. A constant average rate of penetration may be assumed.

FIG. 14 compares responses for sensors having measurements that depend on an independent variable linearly, exponentially, inversely, or as a square root. For example, the independent variable may be time or depth. The present invention is not limited to a specific independent variable. For the sensors having measurements that depend on the independent variable linearly, the equation y=ax+b may be used. The sensors may be located at intervals Δx such that the measured quantity y may be regularly spaced. Δy may be approximately constant. Taking the derivative and solving for Δx leads to Δx=Δy/a. Since Δy may be approximately constant, Δx may be approximately constant, and the sensors may be distributed uniformly along the drill string 14.

For the sensors having measurements that depend on the independent variable exponentially, the equation y=a exp(±bx) may be used. Taking the derivative and solving for Δx leads to Δx=±(Δy/ab)exp(±bx). Thus, for the sensors having measurements with an exponential growth (positive exponent) dependence, the distance between adjacent sensors may decrease exponentially. For the sensors having measurements following an exponential decay (negative exponent) dependence, the distance between adjacent sensors may increase exponentially.

Similarly, for the sensors having measurements that depend on the independent variable inversely, the equations y=a/(bx) and/or Δx=−(bΔy/a)x² may be used. Thus, the sensors having measurements that depend on the independent variable inversely may be distributed such that the distance between adjacent sensors may increase as x². For the sensors having measurements that depend on the independent variable as a square root, y=a sqrt(bx) and Δx=(2Δy/a sqrt(b))sqrt(x). Thus, the sensors having measurements that depend on the independent variable as a square root may be distributed as sqrt(x) which varies with x, but the distance variation in successive pairs of the sensors may become smaller as x increases. The present invention is not limited to the dependences discussed above, and any dependence on x may be analyzed by taking the derivative and solving for variation in x.

FIG. 15 shows a graph of Δx versus x for the dependences discussed above. The sensors having measurements that depend on the independent variable linearly may have a constant distance between the adjacent sensors. The sensors having measurements that depend on the independent variable inversely and the sensors having measurements that depend on the independent variable as a square root may require more closely spaced sensors at the outset and increasingly less of the sensors at later times. The sensors having measurements that depend on the independent variable exponentially require less sensors at the outset and increasingly more closely spaced sensors at later times.

The measurements of the sensors may be characterized in one of the following two categories: measuring a property at the same depth at various times, or measuring a property at various depths. If the property is measured at the same depth at various times, successive sensors may provide measurements whenever each of the sensors reach the depth. The measurements may be acquired at time intervals that may be based on the rate of penetration and the distance between the sensors. If the property is measured at various depths and is expected to be time independent, then the distributed sensors may provide a continuous log of the property as the drilling proceeds. For both measurement categories, the measurements acquired during drilling may be supplemented by measurements acquired during removal of the drill string 14 from the wellbore.

If the property is measured at the same depth at various times, the sensors may be distributed along the drill string 14. As the drill string 14 travels in a downward direction, different sensors measure the same property at various times. Thus, depending on the type of dependence of the measurement, the distance between the sensors Δx may be adjusted to achieve the desired measurements.

Distribution of fluids within an invaded zone is an example of how the property changes as a function of time. The distribution of fluids may be related to the volume of filtrate. The volume of the filtrate may follow a square root of time dependence. Initially, the volume of filtrate may be large, but as time passes, an increasingly thicker mud cake may be formed that may limit an amount of filtrate entering the formation. Referring to FIGS. 16 and 17, the sensors for determining the volume of filtrate may be spaced closer together at short times and may be spaced farther apart at longer times. Such spacing of the sensors may be consistent with more available area for sensor placement in a section of the drill string 14 close to the drill bit 15 relative to sections of the drill string 14 farther away from the drill bit 15.

FIG. 16 shows a possible sensor distribution for measurement of the volume of filtrate. A first sensor 401 and/or a second sensor 402 may be located on or adjacent to the BHA 10. A third sensor 403, a fourth sensor 404 and/or a fifth sensor 405 may be connected to the wired drill pipe 20. The distances between the sensors 401-405 may be any predetermined distances appreciated by a person having ordinary skill in the art. The distances between the sensors 401-405 may be similar, the same, or different. For example, the first sensor 401 may be a first distance D1 from the second sensor 402, and the second sensor 402 may be a second distance D2 from the third sensor 403 which may be greater than the first distance D1. The fourth sensor 404 may be a third distance D3 from the third sensor 403 which may be greater than the first distance D1 and the second distance D2. The fifth sensor 405 may be a fourth distance D4 from the fourth sensor 404 which may be greater than the first, second and third distances D1-D3. FIG. 16 illustrates an embodiment of spacing the sensors 401-405 with arbitrary units, but the invention should not be deemed as limited to these distances as previously mentioned. The second sensor 402 may be one unit from the first sensor 401, the third sensor 403 may be 1.42 units from the second sensor 402, the fourth sensor 404 may be 1.72 units from the third sensor 403 and/or the fifth sensor 405 may be two units from the fourth sensor 404. The present invention is not limited to specific distances between the first sensor 401, the second sensor 402, the third sensor 403, the fourth sensor 404 and/or the fifth sensor 405 (hereinafter “the sensors 401-405”).

The third sensor 403, the fourth sensor 404 and/or the fifth sensor 405 may be the dual purpose modules that may perform both measurement functions and repeater functions. The sensors 401-405 may be a resistivity sensor and/or a sensor capable of measuring a thickness of the mud cake, for example. The sensors 401-405 may be a different type of sensor capable of measuring a thickness of the mud cake may also require the same axial distribution. For example, the sensor capable of measuring the thickness of the mud cake may be an ultrasonic sensor that measures the thickness using ultrasonic wave reflections from the formation and an interface of the mud and the mud cake. The present invention is not limited to a specific embodiment of the sensors 401-405.

The depth of investigation of the sensors 401-405 may be adjusted. For example, the first sensor 401 and/or the second sensor 402 may be resistivity sensors and/or may have relatively shallow depths of investigation. The third sensor 403, the fourth sensor 404 and/or the fifth sensor 405 may be resistivity sensors and/or may have increasingly larger depths of investigation. As a further example, the first sensor 401 and/or the second sensor 402 may be ultrasonic sensors and/or may have very fine resolution to handle very thin mud cakes. The third sensor 403, the fourth sensor 404 and/or the fifth sensor 405 may be ultrasonic sensors and/or may have less resolution to handle thick mud cakes.

Assuming a piston-like invasion, an invasion front may follow fourth root of time dependence. The filtrate may push the invasion front away from the wellbore to cause a cylindrical invasion. A cross section of the cylinder may be a circle with the invasion front being the radius of the circle. The filtrate volume may be proportional to the area of the circle. Since filtrate volume may vary with the square root of time, πr² α sqrt (t) or r α ⁴sqrt(t). The sensors may be positioned at appropriate locations to monitor the invasion front. Some of the sensors may be located on the BHA 10. Other sensors may be located on the dual purpose modules connected to the wired drill pipe 20.

Some properties of the mud column and the formation are depth dependent but change minimally as a function of time. For example, the formation temperature increases linearly with depth, and the drilling process may not change the formation temperature significantly. If mud density and gravitational acceleration do not change, pressure of the mud column is a function of depth and changes minimally as a function of time. If the property is measured at various depths and is expected to be time independent, the distributed sensors may provide a continuous log of the property as the drilling proceeds. For measurements of the property at various depths, the distance between the sensors may be a function of how the property varies with depth. Thus, sensor spacing for measurements of a time independent property at various depths may be similar to measurements of a property at the same depth at various times.

Distributed pressure sensors that may measure hydrostatic mud column pressure in the wellbore may follow the relationship P=ρgh where P is the pressure, ρ is average mud density, g is gravitational acceleration and h is the height of the mud column. Since P varies linearly with h (assuming g remains constant), the optimum distribution for the sensors may be equidistant, as generally shown in FIG. 17. Each of the repeaters 100 may be equipped with a pressure sensor, and the dual purpose modules may be distributed at equal distances along the drill string 14. The distance may be based on a desired pressure resolution and/or the rate of penetration, for example.

Similarly, when measurement of temperature as a function of depth is required, temperature sensors may be coupled with the repeaters 100 in the dual purpose modules. Since the temperature may vary linearly with depth, the dual purpose modules may be distributed at equal distances along the drill string 14, as generally shown in FIG. 17 where the distances D1-D4 are displayed as approximately equal. The distance may be based on a desired temperature resolution and/or the rate of penetration, for example.

If the sensor intervals are the same as the distance required for the repeaters 100, the dual purpose modules may be employed throughout. If the sensor intervals are longer than the distance required for the repeaters 100, some of the dual purpose modules may be replaced with modules having either no sensing capability or having sensors of a different nature. Alternatively, dual purpose modules may be employed throughout with the sensor measurement at distances less than the interval treated as additional information or not used. The wired drill pipe 20 may support communication of the measurements from the additional sensors.

If the sensor intervals are shorter than the distance required for the repeaters 100, some of the dual purpose modules may be replaced with modules that do not perform repeater functions. Alternatively, dual purpose modules may be employed throughout. Additional repeaters 100 may enhance the quality of the signal transmitted by the wired drill pipe 20.

FIG. 18 generally illustrates the resistivity tool 40 in an embodiment of the present invention. The electromagnetic signal may be transmitted into the formation from the transmitter module 55 and/or may be received by one or more of the receiver modules 51, 52, 61, 62. The electromagnetic signals received by the receiver modules 51, 52, 61, 62 may be processed using two different approaches, namely a relative approach and an absolute approach. In the absolute approach, each of the receiver modules 50 may be treated independently. For example, the absolute approach may be a measure of the signal strength at the transmitter module 55 minus the signal strength at one of the receiver modules 51, 52, 61, 62 (T−Rx). An amplitude and/or phase data may be used to determine formation properties that have influenced the electromagnetic signal. In the absolute approach, the electromagnetic signal may have a depth of investigation that may be approximately proportional to the distance between the transmitter antenna of the transmitter module 55 and the receiver antenna of the receiver module 50. At low frequencies of the electromagnetic signal, a resolution of the electromagnetic signal may be approximately proportional to the distance between the transmitter antenna of the transmitter module 55 and the receiver antenna of one of the receiver modules 51, 52, 61, 62. A gain of the transmitter antenna of the transmitter module and/or the receiver antenna of the receiver module 50 may be measured before transmittal of the electromagnetic signal.

In the relative approach, the measurements from at least two of the receiver modules 50 may be combined to determine a relative signal. The relative signal may be the ratio of the voltages or, if the electromagnetic signals are expressed in decibels, the difference between the strength of the signals. For example, the relative approach may be the difference in signal strength between the transmitter module 55 and the receiver module 51 divided by the difference in signal strength between the transmitter module 55 and the receiver module 52. Of course, this approach may be applied for any of the receiver modules 51, 52, 61, 62. The relative signal may have a depth of investigation that may be proportional to the distance between the receiver antennas of the receiver modules 50. The distance between the receiver antennas of the receiver module 51 may be less than the distance from one of the receiver antennas of the receiver modules 52, 61, 62 to the transmitter antenna of the transmitter module 55. The relative signal may have a smaller depth of investigation relative to the electromagnetic signal. Resolution of the relative signal may be a function of the distance between the receiver antennas and/or may be higher than the resolution of the electromagnetic signal of the absolute approach. The resolution of the relative signal may be adjusted to a desired value in designing the propagation electromagnetic logging tool.

For the relative signal, the gain of the transmitter antenna may be canceled by taking the ratio of the electromagnetic signals received by the receiver antennas. Thus, the gain of the receiver antennas may be determined and/or the gain of the transmitter antenna may not be determined for the relative approach.

The high resolution provided by the relative signal of the receiver antennas of the receiver modules 51, 52, 61, 62 may be implemented for measurements acquired proximate to the wellbore 30. For example, as shown in FIG. 19, the resistivity tool 40 may have the transmitter module 55 located adjacent to the drill bit 15. The resistivity tool 40 may have the first receiver module 51 and/or the second receiver module 52 distributed within the BHA 10. The resistivity tool 40 may use the absolute approach by treating the first receiver module 51 and the second receiver module 52 independently and/or using the amplitude and/or the phase data to determine the formation properties that have influenced the electromagnetic signal. The resistivity tool 40 may use the absolute approach to determine the formation properties at relatively large radial distances from a wall of the wellbore 30.

As shown in FIG. 20, the receiver module 51 may have a first receiver antenna 151 and a second receiver antenna 152. In FIG. 20, the dipole moments of the first antenna 151 and/or the second antenna 152 of the receiver module 51 are shown. In the embodiment depicted in FIG. 20, the first receiver antenna 151 and/or the second receiver antenna 152 of the receiver module 51 may be tilted at an angle with respect to the axis of the first receiver module 51, such as approximately forty-five degrees. The electromagnetic signals received by the first receiver antenna 151 and/or the second receiver antenna 152 of the receiver module 51 may be processed in combination using the relative approach to provide high resolution information about the formation. A desired resolution may be selected, and the receiver antenna 151 may be connected to the receiver module 51 at a distance from the second receiver antenna 152 of the first receiver module 51 such that the distance provides the selected resolution. Thus, electromagnetic signals from the transmitter module 55 may be processed using both the absolute approach and the relative approach. Of course in embodiments, the above-description could apply to any one of the receiver modules 51, 52, 61, 62.

The dual purpose modules of the receiver modules 51, 52, 61, 62 may have the repeater function in addition the first receiver antenna 151 and/or the second receiver antenna 152. The dual purpose module may have threads 160 on a female portion 161 and/or a male portion 162 for connecting to sections of the wired drill pipe 20.

As shown in FIG. 21, the resistivity tool 40 may have the receiver modules 61, 62 located at distances from the transmitter module 55, such as distances longer than one hundred feet. The distances of the receiver modules 61, 62 from the transmitter module 55 may provide a deeper depth of investigation relative to the receiver modules 51, 52. However, the signal level may be lower relative to the receiver modules 51, 52 due to the distances of the receiver modules 61, 62 are from the transmitter module 55. The receiver modules 61, 62 may use the HSR antennas and/or a lower frequency of operation to enhance the signal level. A higher power level of transmission may be used to enhance the received signal level. The receiver modules 61, 62 may be combined with the repeaters 100 to provide the dual purpose modules that may perform both the measurement functions and the repeater functions.

The dual purpose modules of the receiver modules 61, 62 may be equipped with at least two of the HSR antennas for processing of the electromagnetic signals using the absolute approach and/or the relative approach. As discussed previously, the relative signal may have higher resolution and a shallower depth of investigation relative to the electromagnetic signal processed using the absolute approach. The electromagnetic signals may be processed using the absolute approach for deeper depth of investigation relative to the relative approach. The distance between the dual purpose modules of the receiver modules 61, 62 may be designed to achieve the desired depth of investigation and the desired resolution.

The transmitter antennas and the receiver antennas may be coils wound to generate a magnetic dipole. The coils may wind along the axis of the module and/or the wellbore to generate a dipole moment in the same direction and/or to form a z axis coil. Alternatively, the coils may be tilted or transverse relative to the axis of the module and/or the wellbore 30. A tool may have any combination of antenna orientations. For example, the transmitter module 55 and/or the receiver modules 51, 52, 61, 62 may have any combination of antenna orientations. The receiver modules 51, 52, 61, 62 may have two antennas having the same orientation, such as, for example, both tilted or both transverse. The electromagnetic signals from antennas having the same orientation may be easier to combine and interpret relative to signals from antennas having different orientations.

Antennas having different orientations may provide advantages. For example, as shown in FIG. 22, the first antenna 151 of the receiver module 51 may be tilted at a first angle, such as forty-five degrees, relative to the axis of the first receiver module 51. Thus, the first receiver antenna 151 of the first receiver module 51 may act as a combination of an x-directed receiver and a z-directed receiver. The second receiver antenna 152 of the receiver module 51 may be tilted at a second angle, such as 135 degrees, relative to the axis of the first receiver module 51. Thus, the second receiver antenna 152 of the receiver module 51 may act as a combination of an x-directed receiver and a z-directed receiver. The arrangement depicted in FIG. 22 may enable the sum and the difference of signals from the first receiver antenna 151 and the second receiver antenna 152 of the receiver module 51 to provide pure x-directed receivers and pure z-directed receivers with information different than that acquired by the pure x-directed receivers and the pure z-directed receivers.

In summary, the resistivity tool 40 may have the transmitter module 55 and the receiver modules 51, 52 that may be located adjacent to the drill bit 15, and the receiver modules 61, 62 located at greater distances from the drill bit 15 relative to the receiver modules 51, 52. The receiver modules 51, 52, 61, 62 may also perform repeater functions for the wired drill pipe 20. The resistivity tool 40 may provide information regarding the region of interest 150. The resistivity tool 40 may be used in two or more wells to improve accuracy of determination of position of the wells relative to each other and/or a reference point. In some implementations additional measurements other than resistivity may be made where sensors that obtain a measurement may be spaced from each other based on the dependence of the measurement on an independent variable.

It should be understood that various changes and modifications to the presently preferred embodiments described herein will be apparent to those having ordinary skill in the art. Such changes and modifications may be made without departing from the spirit and scope of the present invention and without diminishing its attendant advantages. It is, therefore, intended that such changes and modifications be covered by the appended claims.

Claims

1. A system to measure a resistivity of a subsurface formation comprising:

a transmitter module having at least one antenna;

one or more sections of wired drill pipe in communication with the transmitter module; and

a first receiver module having at least one antenna and in communication with the one or more sections of wired drill pipe, wherein the receiver module and the transmitter module are separated by the one or more section of wired drill pipe.

2. The system of claim 1 wherein at least one of the transmitter module and the first receiver module is incorporated into a telemetry repeater in communication with the one or more sections of wired drill pipe.

3. The system of claim 1 wherein at least one of the transmitter module and the first receiver module performs the functions of a telemetry repeater for signals transmitted via the one or more sections of wired drill pipe.

4. The system of claim 1 wherein a distance between the transmitter module and the first receiver module is based on a depth of investigation.

5. The system of claim 1 wherein the first receiver module is located at a distance in excess of 100 feet from the transmitter module.

6. The system of claim 5 wherein the first receiver module is separated from the transmitter module by at least three sections of wired drill pipe.

7. The system of claim 1 further comprising a first clock associated with the transmitter module and a second clock associated with the fist receiver module wherein the first clock and the second clock are synchronized via data transmitted via the one or more sections of wired drill pipe.

8. The system of claim 1 wherein the transmitter module and the first receiver module provide data indicative of a position of a first wellbore relative to a second wellbore.

9. The system of claim 1 wherein the at least one antenna of the transmitter module or the first receiver module is tilted with respect to an axis extending through a length of the transmitter module.

10. The system of claim 1 wherein the at least one antenna of the transmitter module is axial or parallel to an axis extending through a length of the transmitter module.

11. The method of claim 1 wherein bending of the wired drill pipe varies the depth of investigation of the transmitter module and the first receiver module.

12. A system for making a subsurface measurement comprising:

a drill string comprising a plurality of wired drill pipes having a communication channel, the drill string extending into a subsurface formation;

a plurality of sensors distributed at distances along the drill string wherein the distances between the plurality of sensors is determined from an equation; and

wherein the plurality of sensors are in communication with the wired drill pipes.

13. The system of claim 12 wherein at least one of the sensors is located at a telemetry repeater in communication with the plurality of wired drill pipes, and further wherein the telemetry repeater amplifies a signal transmitted along the plurality of wired drill pipes.

14. The system of claim 12 wherein the equation is a linear equation.

15. The system of claim 12 wherein the equation is a exponential equation.

16. The system of claim 12 wherein the equation is a logarithmical equation.

17. The system of claim 12 wherein the plurality of sensors are equally spaced along the drill string.

18. The system of claim 12 wherein the equation describes dependence of subsurface measurement on an independent variable in a linear, inverse, logarithmical, exponential, or a power law fashion.

19. The system of claim 12 wherein the plurality of sensors measure a characteristic of a formation surrounding the drill string.

20. The system of claim 12 wherein the plurality of sensors measure a characteristic of the drill string.