Patent Application
20140151031
In one aspect, this disclosure relates generally to methods for performing measurements in a wellbore with a rotating sensor. More particularly, this disclosure relates to methods, devices, and systems for mitigating effects of torsional noise on measurements from a rotating sensor.
Oil well logging has been known for many years and provides an oil and gas well driller with information about the particular earth formation being drilled. In conventional oil well logging, during well drilling and/or after a well has been drilled, a sensor may be conveyed into a borehole and used to determine one or more parameters of interest of the formation. A rigid or non-rigid conveyance device is often used to transport the sensor, often as part of a tool or set of tools, and the conveyance device may also provide communication channels for sending information up to the surface.
In aspects, the present disclosure is related to methods of estimating a parameter of interest of a formation using information detected from a rotating sensor in a subterranean formation.
One embodiment according to the present disclosure may be an apparatus for mitigation of torsional noise effects on borehole measurements. The apparatus may include a conveyance device; a sleeve having a sensor section, the sleeve rotatably disposed on the conveyance device; a sensor having at least one component disposed on the sensor section; and a driver coupled to the conveyance device and configured to rotate at least the sleeve sensor section.
In general embodiments, the driver may be implemented as at least one of: i) a mud motor; ii) an electric motor; and iii) a hydraulic motor. The driver may rotate the sleeve sensor section independent of the conveyance device. The driver may rotate the sleeve sensor section at a preset substantially constant rotational speed. The sleeve may include at least one arm configured to selectively lock the sleeve to a surface in the borehole. The driver may rotate the sleeve sensor section during measurement by the sensor.
In other general embodiments, the driver may be implemented as a coupler that selectively couples the sleeve with a rotary power source. The rotary power source may be at least one of: i) the conveyance device; ii) a mud motor; iii) an electric motor; and iv) a hydraulic motor. The coupler couples the sleeve with the rotary power source to generate a target speed for the sleeve, and decouples the sleeve from the rotary power source.
In some embodiments, the apparatus includes a second sensor providing a response relating to a parameter of a fluid in viscous contact with the sleeve; and a processor configured to account for decay of rotational speed of the sleeve using an estimated viscosity of the fluid. The sleeve may include an actively stabilized non-rotating section disposed on the conveyance device. The at least one sensor component may include a magnet-coil assembly, which may have multiple receiving coils at different radii with respect to the axis of rotation of the sleeve. At least a magnet and at least one of the multiple receiving coils of the magnet-coil assembly may be mounted on the sleeve.
Another embodiment according to the present disclosure may be a method for mitigating torsional noise effects on borehole measurements, the method comprising disposing a sleeve having a sensor section on a conveyance device with at least one component of a sensor disposed on the sensor section; and rotating at least the sleeve sensor section independently of the conveyance device during measurement by the sensor.
Another embodiment according to the present disclosure may be a method for estimating a parameter of an earth formation, comprising: estimating the parameter using information from a rotating sensor incorporated into an apparatus of the present disclosure.
Another embodiment according to the present disclosure may be an apparatus for estimating a parameter of an earth formation, comprising: a processor; a subsystem non-transitory computer-readable medium; and a program stored by the non-transitory computer-readable medium comprising instructions that, when executed, cause the processor to estimate the parameter using information obtained from a rotating sensor incorporated in the apparatus of the present invention.
Examples of features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated.
For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:
In aspects, this disclosure relates to mitigation of torsional noise effects on borehole measurements. A rotating borehole sensor may be sensitive to instability in rotational speed during measurement, causing inaccuracies during measurement. In many applications, this sensitivity is exacerbated by the sensor being coupled to a conveyance device experiencing unpredictable variations in rotational speed, or torsional noise, such as, for example, a rotating member of a bottom hole assembly (‘BHA’).
General embodiments of the present disclosure include methods, devices, and systems to generate angular speed for the sensor while mitigating effects of rotational vibration. Rotational vibration may be characterized as chaotic variations in angular speed that cause uncertainty in the angular speed. Mitigation may be achieved by mechanically decoupling the rotation of the sensor from the variable rotation of the conveyance device.
For some BHA applications, measurements may be taken during drilling operations, although in others drilling may be stopped. There may be a different measurement mode associated with each of measurement while drilling (“while-drilling”) and measurement while drilling is stopped (“stop-drilling”). The “stop-drilling” mode may provide more accurate measurement, but may slow down drilling operations. The “while-drilling” mode may perform wellbore proximity measurement continuously while-drilling, but may provide measurement having lower accuracy. The devices and systems of the present disclosure may also be used in wireline or other non-drilling applications.
The sensor may be a downhole acoustic sensor used for 3-D imaging of the formation surrounding the wellbore. In another example, the sensor may be an electromagnetic sensor used to determine direction and/or distance to another borehole (e.g, a pre-existing well). Such a sensor may comprise an assembly including a magnet and a coil (magnet-coil assembly), wherein the magnet is used to create a time varying magnetic field in the other borehole, providing magnetization in a magnetic object in the other borehole; and a signal responsive to a magnetic flux resulting from the magnetization is measured using the coil. Methods using the magnet-coil assembly may estimate direction and/or distance to the pre-existing well and then use the estimated direction/distance to maintain a trajectory of the borehole in a desired relation (parallel, intersecting, etc.) to the other borehole.
In further examples, the sensor may provide information relating to a geological parameter, a geophysical parameter, a petrophysical parameter, and/or a lithological parameter. Example sensors may include formation evaluation sensors such as resistivity sensors, nuclear magnetic resonance (NMR) sensors, gamma ray detectors, and other sensors. Thus, sensors may include sensors for estimating formation resistivity, dielectric constant, the presence or absence of hydrocarbons, acoustic porosity, bed boundary, formation density, nuclear porosity and certain rock characteristics, permeability, capillary pressure, and relative permeability. It should be understood that this list is illustrative and not exhaustive.
The device also includes a driver 170 coupled to the conveyance device 110 and configured to rotate at least the sleeve sensor section 130. Driver 170 may rotate the sleeve sensor section 130 during measurement by the sensor 140. Driver 170 comprises an independent motor. The motor employed may be one or more of a mud motor, an electric motor, and a hydraulic motor. Other embodiments using concentric configurations (see
Alternatively, the sleeve may be concentrically mounted on the conveyance device or on a separate rotary power source, as illustrated in
Driver 175 comprises a coupler that selectively couples the sleeve with a rotary power source. Coupler 175 rotates the entire sleeve 125. Coupler 175 may be implemented as a cylindrical clutch. Embodiments using end-to-end configurations (see
In some embodiments, additional protective members (skins, sleeves, or sheets) may enclose the sleeve, sensor section, sensor components, or a combination of these. For example, the sensor components and all or a portion of the sleeve sensor section may be isolated from external drilling mud and cuttings by a thin sheet of protective metal skin. The spacing between the protective metal skin and the sensor components inside may be filled with a fluid (e.g., low-viscosity hydraulic fluid, well fluids, etc.) for pressure balancing in an open or closed system.
For coupler embodiments (see
Although
V
REFα cos(2ωt),
synchronized with the magnet/coil rotation, the following expression for the voltage on the coil 208 can be written
V
REF
=Vm·cos [2(ωt+φ0)],
Here φ0 is the azimuth of the casing with respect to the pre-existing well casing. Thus the phase of the signal on the coil 208 is sensitive to the azimuthal position of the casing 205 with respect to the pre-existing well casing 230.
According to prior art, the approximate result of the receiver voltage takes the following form:
Here μ0 is the vacuum permeability;
χeffz is the effective magnetic susceptibility of the casing;
ACASING is the cross-sectional area of the casing;
ACOIL is the area of the receiver coil;
pm is the magnetic moment of the rotating magnet;
ω is the angular frequency of the magnet/coil assembly; and
r is the distance between the rotating magnet/coil assembly and the casing.
The above expression indicates that in order to obtain signals in the coil, the magnet/coil assembly needs to maintain an angular frequency ω with respect to the center of the drill collar. Since the signal induced by the rotating magnetization of the casing has a frequency which is twice the rotation frequency of the magnet/coil assembly, in ideal conditions the measured proximity signal is separable from a parasitic signal induced in the rotating coil due to the earth's magnetic field, which has a frequency equal to the magnet/coil rotation frequency. However, if the rotational speed of the magnet/coil assembly is not substantially constant, the parasitic signal from the earth's magnetic field will have a spectral component at twice the rotation frequency of the magnet/coil assembly, which is the same frequency as the measured proximity signal. Such parasitic signal cannot be removed by a frequency-domain filter and will remain as a problematic source of noise in the final result.
The device as described above is capable of generating angular speed for the magnet/coil assembly for well-bore proximity measurement using a rotating magnet while reducing rotational vibration sufficiently to mitigate parasitic signals from the earth's magnetic field.
Referring to
Referring to
The non-rotating sleeve 302 provides a stationary base from which a precise speed of rotation may be achieved for the sensor section. The non-rotating sleeve 302 is a generally tubular element that is telescopically disposed around a bearing assembly housing 320. The sleeve 302 engages the housing 320 at bearings 322. The bearings 322 may include a radial bearing 324 that facilitates the rotational sliding action between the sleeve 302 and the housing 320 and a thrust bearing 324 that absorbs the axial loadings caused by the thrust of the drill bit against the borehole wall. Preferably, bearings 322 include mud-lubricated journal bearings 324 disposed outwardly on the sleeve 302.
Each of the above embodiments may be used in a variety of settings in both drilling and non-drilling environments. In some implementations, the above embodiments may be used as part of a drilling system.
During drilling operations, a suitable drilling fluid 431 from a mud pit (source) 432 may be circulated under pressure through a channel in the drill string 440 by a mud pump 434. The drilling fluid passes from the mud pump 434 into the drill string 420. The drilling fluid 31 may be discharged at the borehole bottom 451 through an opening in the drill bit 450. The drilling fluid 431 may circulate uphole through the annular space 427 between the drill string 420 and the borehole 426 and return to the mud pit 432 via a return line 435. The drilling fluid acts to lubricate the drill bit 450 and to carry borehole cutting or chips away from the drill bit 450.
In one embodiment of the disclosure, the drill bit 450 is rotated by only rotating the drill pipe 422. In another embodiment of the disclosure, a downhole motor 455 (mud motor) is disposed in the drilling assembly 490 to rotate the drill bit 450 and the drill pipe 422 is rotated usually to supplement the rotational power, if required, and to effect changes in the drilling direction.
In the embodiment of
A suitable telemetry or communication sub 472 using, for example, two-way telemetry, may also be provided. The drilling sensor module processes the sensor information and transmits it to the surface control unit 440 via the telemetry system 472. The communication sub 472, a power unit 478 and an MWD tool 479 may all be connected in tandem with the drillstring 420. The communication sub 472 obtains the signals and measurements and transfers the signals, using two-way telemetry (i.e., uplink, downlink), for example, to be processed on the surface. Alternatively, the signals can be processed using a downhole processor in the drilling assembly 490.
The surface control unit or processor 440 may also receive signals from other downhole sensors and devices and signals from sensors used in the system 410 and process such signals according to programmed instructions provided to the surface control unit 440. The surface control unit 440 preferably includes a computer or a microprocessor-based processing system, memory for storing programs or models and data, a recorder for recording data, and other peripheral devices.
To identify and quantify parameters of interest, rotating sensors may be configured to acquire information relating to the downhole feature(s) of interest. The sensors may be in signal communication with a controller (not shown) via a suitable communication line. It should be understood that the type of sensors used on tool may depend in part on the downhole feature to be investigated.
Operation of the system may depend on the particular implementation of the device. Particular implementations may lend themselves to performing at least a portion of the measurement while rotation of the conveyance device is stopped (“stop-drilling” mode), while rotation of the conveyance device is occurring (“while-drilling” mode), or both.
Returning to
Returning to
The rotational speed of the sensor may decay due to friction. An information processing device may account for the effect of the decay on measurements from the sensor 145 using historical or real-time parameters relating to environmental conditions correlated with the decay. For example, the information processing device may compensate for the broadening of the frequency spectrum caused by the decay to improve filtering of a parasitic signal as described above.
By geo-stationary it is meant that the sleeve does not move with respect to the surrounding wellbore/earth formation. By “substantially geo-stationary,” it is meant rotation at a rate sufficiently low to allow use of the sensor to determine a parameter of interest of the borehole, examples of such a rate including, for example, fewer than 1 turn per minute, 20 turns an hour, 10 turns an hour, 1 turn an hour, and so on, down to and including zero rotation.
The term “conveyance device” as used above means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting conveyance devices include drill strings of the coiled tube type, of the jointed pipe type and any combination or portion thereof. Other conveyance device examples include casing pipes, wirelines, wire line sondes, slickline sondes, drop shots, downhole subs, BHA's, drill string inserts, modules, internal housings and substrate portions thereof, self-propelled tractors. The term “information” as used above includes any form of information (analog, digital, EM, printed, etc.). The term “information processing device” herein includes, but is not limited to, any device that transmits, receives, manipulates, converts, calculates, modulates, transposes, carries, stores or otherwise utilizes information. An information processing device may include a microprocessor, resident memory, and peripherals for executing programmed instructions.
Substantially constant rotational speed may be defined as an instantaneous rotational speed at a standard deviation within 2 percent, 1 percent, 0.5 percent, 0.2 percent, 0.1 percent, or less of its average value; a rotational speed enabling measurement of the instantaneous rotational speed at an accuracy with a relative error less than 2 percent, 1 percent, 0.5 percent, 0.2 percent, 0.1 percent, or less; a rotational speed sufficiently constant to result in a spectral component of a parasitic signal from the earth's magnetic field at less than 10, 5, 2, 1, 0.5, 0.2, or 0.1 percent of the sensor signal for an electromagnetic sensor; or a rotational speed with sufficient stability such that measurement error of the sensor due to torsional noise is less than 2, 1, 0.5, 0.2, or 0.1 percent.
While the present disclosure is discussed in the context of a hydrocarbon producing well, it should be understood that the present disclosure may be used in any borehole environment (e.g., a water or geothermal well).
The present disclosure is susceptible to embodiments of different forms. There are shown in the drawings, and herein are described in detail, specific embodiments of the present disclosure with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure and is not intended to limit the disclosure to that illustrated and described herein. While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.
