Geologic formations below the surface of the earth may contain reservoirs of oil and gas, which are retrieved by drilling one or more boreholes into the subsurface of the earth. The boreholes are also used to measure various properties of the boreholes and the surrounding subsurface formations.
Oil and gas retrieval and measurement processes often involve the use of multiple boreholes. Multiple boreholes are useful, for example, in maximizing oil and gas retrieval from a formation and establishing sensor arrays for formation evaluation (FE) purposes.
An example of a multiple borehole oil and gas retrieval system is a Steam Assisted Gravity Drainage (SAGD) system that is used for recovering heavy crude oil and/or bitumen from geologic formations, and generally includes heating the bitumen through an injection borehole until it has a viscosity low enough to allow it to flow into a parallel recovery borehole. As used herein, “bitumen” refers to any combination of petroleum and matter in the formation and/or any mixture or form of petroleum, specifically petroleum naturally occurring in a formation that is sufficiently viscous as to require some form of heating or diluting to permit removal from the formation.
Generally, implementation of a multiple borehole system includes detecting a location of a first borehole when drilling a second borehole in order to avoid contact between the boreholes and/or accurately position the boreholes relative to one another. Such detection may involve the use of antennas that act as transmitters and receivers to interrogate an earth formation. Examples of such antennas include so-called “slot” design antennas, such as “Z-type” antennas (“Z-antennas”) typically used in multi-frequency and multi-spacing propagation resistivity (“MPR”) tools and “X-type” antennas (“X-antennas”) typically used in azimuth propagation resistivity (“APR”) tools. Accurate detection of borehole position can be difficult, as direct coupling of measurement signals between measurement transmitters and receivers can overshadow measurement signals.
Disclosed herein is an apparatus for detecting a position of a component in an earth formation. The apparatus includes: a transmitter configured to emit a first magnetic field into the earth formation and induce an electric current in the component, the transmitter having a first magnetic dipole extending in a first direction; and a receiver for detecting a second magnetic field generated by the component in response to the first magnetic field, the receiver having a second magnetic dipole extending in a second direction orthogonal to the first direction.
Also disclosed herein is a method of detecting a position of a component in an earth formation. The method includes: drilling a first wellbore and disposing therein an electrically conductive component; drilling a second wellbore parallel to the first wellbore and disposing therein a downhole tool, the downhole tool including a transmitter having a first magnetic dipole extending in a first direction, the receiver having a second magnetic dipole extending in a second direction orthogonal to the first direction; transmitting a first magnetic field from the transmitter to induce an electric current in the component and an associated second magnetic field; and detecting the second magnetic field by a receiver and calculating at least one of a direction and a distance of the component therefrom.
Further disclosed herein is a computer program product stored on machine-readable media for detecting a position of a component in an earth formation. The product includes machine-executable instructions for: drilling a second wellbore parallel to a first wellbore and disposing therein a downhole tool, the first wellbore including an electrically conductive component therein, the downhole tool including a transmitter having a first magnetic dipole extending in a first direction, the receiver having a second magnetic dipole extending in a second direction orthogonal to the first direction; transmitting a first magnetic field from the transmitter to induce an electric current in the component and an associated second magnetic field; and detecting the second magnetic field by a receiver and calculating at least one of a direction and a distance of the component therefrom.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures.
There is provided an apparatus and method for detecting a position of a component in an earth formation, such as a component of a drillstring or a downhole tool disposed in a borehole. The system and method may be incorporated in any formation production and/or evaluation system that incorporates multiple boreholes. The apparatus includes a transmitter for emitting a first magnetic field into the earth formation and induce an electric current in the component, and a receiver for detecting a second magnetic field generated by the component in response to the first magnetic field. The transmitter has a first magnetic dipole extending in a first direction, and the receiver has a second magnetic dipole extending in a second direction orthogonal to the first direction.
Referring to
The first borehole 12 includes an injection assembly having an injection valve assembly 18 for introducing steam from a thermal source (not shown), an injection conduit 22 and an injector 24. The injector 24 receives steam from the conduit 22 and emits the steam through a plurality of openings such as slots 26 into a surrounding region 28. Bitumen in region 28 is heated, decreases in viscosity, and flows substantially with gravity into a collector 30.
A production assembly is disposed in the second borehole 14, and includes a production valve assembly 32 connected to a production conduit 34. After the region 28 is heated, the bitumen flows into the collector 30 via a plurality of openings such as slots 38, and flows through the production conduit 34, into the production valve assembly 32 and to a suitable container or other location (not shown).
In this embodiment, both the injection conduit 22 and the production conduit 34 are hollow cylindrical pipes, although they may take any suitable form sufficient to allow steam or bitumen to flow therethrough. Also in this embodiment, at least a portion of boreholes 12 and 14 are parallel horizontal boreholes.
In one embodiment, the injection conduit 22 and/or the production conduit 34 are configured as a drillstring and include a drill bit assembly. In another embodiment, the drillstring includes a steering assembly 40 connected to the drill bit assembly and configured to steer the drill bit and the drillstring through the formation.
A downhole measurement tool 42 is disposed in the borehole 12 and/or the borehole 14. In one embodiment, the tool 42 is disposed within the injection conduit 22 and/or the production conduit 34. In one embodiment, one or more of the conduits 22, 34 are incorporated into a respective drillstring connected to the drilling assembly.
Referring to
As referred to herein, a “Z” direction is a direction parallel to the major axis of the borehole. An “X” direction is a direction orthogonal to the Z direction, and a “Y” direction is a direction orthogonal to both the X and the Z direction. The naming convention described herein is merely exemplary and non-limiting.
In the example shown in
In one embodiment, an optional additional receiver 52 is included in the tool 42 and is configured as a bucking coil. The bucking coil 52 is disposed on the tool 42 between the transmitter 44 and the receiver 46. The bucking coil 52 has a first polarity that is opposite a second polarity of the receiver 46. The bucking coil 52 is configured to reduce or eliminate direct coupling between the transmitter 44 and the receiver 46, which can be much larger than the signal received from the remote pipe 48. In one embodiment, the bucking coil 52 and the receiver 46 coils are physically connected resulting in effectively a single coil, or are separately disposed in the tool 42.
In one embodiment, the tool 42 is configured as a downhole logging tool. As described herein, “logging” refers to the taking of formation property measurements. Examples of logging processes include measurement-while-drilling (MWD) and logging-while-drilling (LWD) processes, during which measurements of properties of the formations and/or the borehole are taken downhole during or shortly after drilling. The data retrieved during these processes may be transmitted to the surface, and may also be stored with the downhole tool for later retrieval. Other examples include logging measurements after drilling, wireline logging, and drop shot logging. As referred to herein, “downhole” or “down a borehole” refers to a location in a borehole away from a surface location at which the borehole begins.
In one embodiment, the tool 42 includes suitable communications equipment for transmitting data and communication signals between the tool 42 and a remote processor. The communications equipment may be part of any selected telemetry system, such as a wireline or wired pipe communication system or a wireless communication system including mud pulse telemetry and/or RF communication.
In one embodiment, the tool 42 includes a processor or other unit disposed on or in the tool 42. The processor and the surface processing unit include components as necessary to provide for storage and/or processing of data from the tool 42. Exemplary components include, without limitation, at least one processor, storage, memory, input devices, output devices and the like. As these components are known to those skilled in the art, these are not depicted in any detail herein.
Referring to
where α is an angle between the direction of the receiver dipole (X) and a direction towards the remote pipe 48, and “F” and “A” are constants. The current induced in the pipe is proportional to the component of a transmitter momentum orthogonal to a direction towards the pipe, i.e., to sin α. Analogously, the signal S from the induced current in a receiver 46 is also proportional to sin α.
The signal F is the component of the signal S due to direct transmitter-receiver coupling, which is not dependent on the signal from the remote pipe 48. The constant A depends on the distance to the pipe, thus calculation of A can yield a distance to the remote pipe 48.
Thus, by making a simple two-term Fourier analysis of equation (1), for some acquired data set for different rotation phases, the constants F and A can be determined, and accordingly, distance and angle can be determined. In one embodiment, a formation resistivity “Rt” is also utilized in determining the constants.
In one embodiment, the dipoles of the transmitter 44 and the receiver 46 are orthogonal (e.g., one is X-directed and another is Y-directed), so the signal represented by F is substantially suppressed, and thus the signal S can be represented by:
In one embodiment, an additional constant term Fres is a component of the signal S, represented by residual direct coupling caused by non-perfect transmitter-receiver orthogonality due to, for example, manufacturing imperfections and tool twisting. A Fourier analysis such as subtraction of a mean value is used to filter out this component.
Referring to
In this example, the tool 42 is centered in a borehole having an 8.5 inch diameter that is filled with an oil-based mud or drilling fluid. The remote component, such as the pipe 48, diameter is also 8.5 inches. The calculations are conducted for frequencies ranging from 1 kHz to 2 MHz, for formation resistivities from 10 to 104 ohmm, and for distance to the ranged pipe of 2.5 meters and 5 meters. In this example, the formation 16 includes oil sands and has an average resistivity Rt of 100 ohmm.
In this example, it can be seen that for low frequencies, i.e., less than approximately 100 kHz, the signal S is too low to be reliably detected, assuming an exemplary detection threshold of 10 nV. For frequencies greater than 100 kHz, the signal is detectable. For example, for Rt=100 ohmm, D=5 m, and frequency f=1 MHz, the signal is 140 nV.
The obtained set of results, for frequencies >100 kHz and Rt<1,000 ohmm, is approximately represented by the following semi-empirical formula:
In this equation, “C” is a tool constant, ω=2πf, and “μt” is the formation permeability. As shown, the dependence of the signal on the distance D is a product of two multipliers: a “geometric” multiplier D−2 and a skin-effect factor
The distance D can be derived based on this equation from an acquired signal having a known resistivity.
It follows from formula (3) and the calculated data for Rt=100 ohmm, D=5 m, that the signal threshold 10 nV is achieved, in this example, when D≈9 m. Accordingly, in this example, for frequency of approximately 1 MHz and the exciting current 2 A, a distance D can be derived from a signal from a component up to approximately 9 meters away from the receiver 46.
The angular behavior of the signal S, represented by equation (2), can be caused not only by a remote conductive pipe 48 but also by deviations from azimuthal symmetry of a formation. Use of two-coil bucking, i.e., inclusion of the bucking coil 52, significantly reduces the signal resulting from asymmetry.
Referring to
In this example, the bucked configuration of the tool 42 includes two receivers, i.e., the receiver 46 and the bucking coil 52, spaced from the X-transmitter 44 by 1 meter and 1.6 meters, respectively. The unbucked configuration does not include the bucking coil 52. The range of frequencies applied is between 1 kHz to 2 MHz, the formation resistivity is 100 ohmm, and the borehole has a 8.5 inch diameter and is filled with conductive mud having a resistivity of 0.1 ohmm.
Two formation examples are represented. The curves 70 and 72 represent a signal from the formation 16 with no remote pipe 48 present using the tool 42 in the unbucked configuration with 0.5 inch eccentricity. The curve 74 represents a signal from the formation 16 with no remote pipe 48 present using the tool 40 in the bucked configuration with 0.5 inch eccentricity.
The curve 76 represents a signal from a formation with a remote pipe 48 five meters away, using the tool 40 in the unbucked configuration with no eccentricity and a spacing between the transmitter 42 and the receiver 44 of one meter and 1.6 meters. The curve 78 represents a signal from the formation 16 with a remote pipe 48 five meters away, using the tool 42 in the bucked configuration with no eccentricity.
The signal from the tool 42 in the bucked configuration, in one embodiment, is represented by the equation:
S=Slong−aSshort, (4)
where Slong is the component of the signal S from the receiver 46 and Sshort is the component of the signal S from the bucking coil 52, “a” is a bucking coefficient chosen to minimize an undesirable component of a signal. A proper choice of a could completely eliminate the parasite signal, but in practice effectiveness of the elimination is limited by precision of a calibration, by accuracy of measurements, and by stability of electronics.
In one embodiment, a frequency of the transmitted signal is selected based on the equation (3). The equation (3) is a function of the signal modulus versus frequency, for some given formation resistivity Rt and distance to the pipe D. The signal S has a maximum at the point where the skin-effect attenuation overwhelms the ω2 growth of the signal. Solving the equation for:
the maximum is reached when the following is satisfied:
In this embodiment, selecting an optimal desired frequency includes selecting a desired maximum distance D. For example, assuming that the maximum distance D is 10 meters, and Rt=100 ohmm, the optimal frequency is calculated to be approximately 1 MHz.
Referring to
In one embodiment, the system 80 includes a computer 82 coupled to the tool 60. Exemplary components include, without limitation, at least one processor, storage, memory, input devices, output devices and the like. As these components are known to those skilled in the art, these are not depicted in any detail herein. The computer 82 may be disposed in at least one of the surface processing unit and the tool 42.
Generally, some of the teachings herein are reduced to an algorithm that is stored on machine-readable media. The algorithm is implemented by the computer 82 and provides operators with desired output.
In the first stage 91, the borehole 12 is drilled. An electrically conductive component, for example, a component of a drillstring, is lowered into the borehole 12 during or after drilling.
In the second stage 92, the second borehole 14 is drilled, and the tool 42 is lowered into the borehole 14 during drilling. In one embodiment, the tool 42 is disposed in a portion of a drillstring, for example, in a bottomhole assembly (BHA).
In the third stage 93, an electric current having a selected frequency is applied to the transmitter 44, which transmits a first magnetic field from the transmitter 44 to induce an electric current in the component and an associated second magnetic field.
In one embodiment, the selected frequency is determined based on the average resistivity of the formation 16 and a selected maximum distance. For example, the selected frequency is determined based on equation (5).
In the fourth stage 94, the receiver detects the second magnetic field and generates data representing the second magnetic field. The direction and/or distance of the component is calculated. For example, the direction and/or the distance is calculated based on equations (1) and/or (2). In another example, the distance is calculated based on equation (3). In one embodiment, calculating the direction and/or distance includes performing a Fourier analysis on the data such as by subtraction of a mean value of the data.
The apparatuses and methods described herein provide various advantages over prior art techniques. The apparatuses and methods allow for substantial reduction or elimination of signals from direct coupling between the transmitter and the receiver and from asymmetry of the downhole tool. The systems and methods thus provide a high quality signal representing the remote pipe or other component.
In support of the teachings herein, various analyses and/or analytical components may be used, including digital and/or analog systems. The system may have components such as a processor, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.
Further, various other components may be included and called upon for providing aspects of the teachings herein. For example, a sample line, sample storage, sample chamber, sample exhaust, pump, piston, power supply (e.g., at least one of a generator, a remote supply and a battery), vacuum supply, pressure supply, refrigeration (i.e., cooling) unit or supply, heating component, motive force (such as a translational force, propulsional force or a rotational force), magnet, electromagnet, sensor, electrode, transmitter, receiver, transceiver, controller, optical unit, electrical unit or electromechanical unit may be included in support of the various aspects discussed herein or in support of other functions beyond this disclosure.
One skilled in the art will recognize that the various components or technologies may provide certain necessary or beneficial functionality or features. Accordingly, these functions and features as may be needed in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings herein and a part of the invention disclosed.
While the invention has been described with reference to exemplary embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation or material to the teachings of the invention without departing from the essential scope thereof Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims.
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