None.
The present invention relates generally to downhole measurement tools utilized for measuring electromagnetic properties of a subterranean borehole. More particularly, the invention relates to borehole compensated resistivity logging tools having asymmetric transmitter spacing along the longitudinal axis of the tool.
The use of electrical measurements in prior art downhole applications, such as logging while drilling (LWD), measurement while drilling (MWD), and wireline logging applications is well known. Such techniques may be utilized to determine a subterranean formation resistivity, which, along with formation porosity measurements, is often used to indicate the presence of hydrocarbons in the formation. For example, it is known in the art that porous formations having a high electrical resistivity often contain hydrocarbons, such as crude oil, while porous formations having a low electrical resistivity are often water saturated. It will be appreciated that the terms resistivity and conductivity are often used interchangeably in the art. Those of ordinary skill in the art will readily recognize that these quantities are reciprocals and that one may be converted to the other via simple mathematical calculations. Mention of one or the other herein is for convenience of description, and is not intended in a limiting sense.
Formation resistivity (or conductivity) is commonly measured by transmitting an electromagnetic wave through a formation using a length of antenna wire wound about a downhole tool. As is well known to those of ordinary skill in the art, a time varying electric current (an alternating current) in a transmitting antenna produces a corresponding time varying magnetic field in the formation. The magnetic field in turn induces electrical currents (eddy currents) in a conductive formation. These eddy currents further produce secondary magnetic fields which may produce a voltage response in a receiving antenna. The measured voltage in the receiving antennae can be processed, as is known to those of ordinary skill in the art, to obtain one or more measurements of the secondary magnetic field, which may in turn be further processed to estimate formation resistivity (conductivity) and/or dielectric constant. These electrical formation properties can be further related to the hydrocarbon bearing potential of the formation via techniques known to those of skill in the art.
It is also well known that a transmitted electromagnetic wave is typically both attenuated and phase shifted by an amount related to the resistivity and/or dielectric constant of the formation. The transmitted wave is commonly received at first and second spaced receiving antennae. The attenuation and phase shift between the first and second receivers are commonly acquired by taking a ratio of the received waves. The attenuation and/or phase shift may then be utilized to estimate the formation resistivity. In order to acquire more data, e.g., at multiple depths of investigation into the formation, it is well known to make the above measurements using multiple spaced transmitters since the depth of penetration of an electromagnetic wave into the formation tends to increase with increased spacing between the transmitter and receiver. The use of multiple perturbation frequencies is also a known means of investigating multiple depths of investigation since the depth of penetration tends to be inversely related to the frequency of the propagated electromagnetic waves.
In order to accommodate errors introduced by the receiver electronics (e.g., due to thermal drift downhole), conventional resistivity measurements commonly employ a compensation scheme. One such compensation technique is to configure a resistivity tool with symmetric transmitters (i.e., with the transmitters deployed axially symmetrically about the receivers).
U.S. Pat. No. 6,218,842 discloses an alternative compensation scheme in which a single compensating transmitter is deployed axially between the receivers. During drilling operations, the calibrating transmitter generates an electromagnetic wave that is detected by each of the receivers. The difference in attenuation and phase shift between the detected signals is used to calibrate the receivers for thermal drift. While this approach may overcome the above described problems, it requires that the calibrating transmitter be located precisely between the receivers. Any errors in placement (or tool body deformation due to the extreme borehole temperature and pressure) can result in significant calibration errors.
Therefore, there remains a need in the art for further improved resistivity logging tools, and in particular improved compensation schemes for such resistivity logging tools.
Aspects of the present invention are intended to address the above described need for an improved resistivity logging tool. In one aspect the present invention includes a logging while drilling resistivity tool having a plurality of spaced transmitters deployed on one axial side of first and second receivers. The tool further includes first and second compensating transmitters, preferably deployed symmetrically between the receivers. The compensating transmitters may be used to acquire a borehole compensation (phase and attenuation errors) that may be subtracted from the conventional phase and attenuation measurements.
Exemplary embodiments of the present invention advantageously provide several technical advantages. For example, exemplary embodiments of the invention advantageously provide for accurate borehole compensation while also providing for a significant reduction in the overall tool length. Tools in accordance with the invention therefore tend to be better suited for high dogleg severity wells and also provide for a more compact BHA.
In one aspect, the present invention includes a logging while drilling resistivity tool. The tool includes a logging while drilling tool body having first and second longitudinally spaced receivers deployed thereon. First and second longitudinally spaced compensating transmitters are deployed axially between the first and second receivers. The compensating transmitters are axially symmetric about a midpoint between the first and second receivers. A plurality of longitudinally spaced transmitters is also deployed on the tool body, the plurality of transmitters being asymmetric with respect to the midpoint. In a preferred embodiment the resistivity tool further includes a controller configured to (i) utilize the first and second compensating transmitters to obtain at least one of an attenuation error and a phase error at the receivers and (ii) subtract the attenuation error and/or phase error from subsequent attenuation and phase measurements made with at least one of the plurality of transmitters and the first and second receivers.
In another aspect, the present invention includes a method for compensating resistivity measurements made in a subterranean borehole. The method includes deploying a resistivity tool in the borehole. The tool includes first and second longitudinally spaced receivers, first and second longitudinally spaced compensating transmitters (the compensating transmitters being axially symmetric about a midpoint between the first and second receivers), and a plurality of longitudinally spaced transmitters. The method further includes causing the first and second compensating transmitters to transmit corresponding first and second compensating electromagnetic waves, measuring a phase shift and an attenuation between the first and second receivers for each of the first and second compensating electromagnetic waves, and computing a phase shift error and an attenuation error from the measured phase shifts and attenuations. The method still further includes causing at least one of the transmitters to transmit an electromagnetic wave, measuring a phase shift and an attenuation between the first and second receivers, and subtracting the computed phase shift error and attenuation error from the measured phase shift and attenuation to obtain a compensated phase shift and attenuation.
The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter, which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiment disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
With continued reference to
Those of ordinary skill in the art will readily appreciate that the magnetic field obtained from a received electromagnetic wave differs from the true magnetic field in the formation due to several environmental factors (e.g., including temperature drift, antenna deformation, and other electronic errors in the receiver). This distortion may be represented mathematically, for example, as follows:
H*(ω)=A(ω)eiΔφH(ω) Equation 1
where H*(ω) represents the measured magnetic field, H (ω) represents the true magnetic field in the formation, A(ω) and Δφ represent the amplitude and phase distortion of the true formation magnetic field, and ω represents the angular frequency of the electromagnetic wave in units of radians. When the compensating transmitters CT1 and CT2 are fired sequentially as described above, the measured magnetic fields at each of the receivers R1 and R2 may be represented mathematically in similar form, for example, as follows:
H*
CT1R1(ω)=CT1(ω)AR1(ω)eiΔφ
H*
CT1R2(ω)=CT1(ω)AR2(ω)eiΔφ
H*
CT2R1(ω)=CT2(ω)AR1(ω)eiΔφ
H*
CT2R2(ω)=CT2(ω)AR2(ω)eiΔφ
where H*CT1R1(ω) and H*CT1R2(ω) represent the measured magnetic fields at the first and second receivers R1 and R2 induced by firing the first compensating transmitter CT1, H*CT2R1(ω) and H*CT2R2(ω) represent the measured magnetic fields at the first and second receivers R1 and R2 induced by firing the second compensating transmitter CT2, HCT1R1(ω), HCT1R2(ω), HCT2R1(ω), and HCT2R2(ω) represent the corresponding true magnetic fields in the formation, AR1(ω), AR2(ω) and ΔφR1, ΔφR2 represent the amplitude and phase distortion of the true formation magnetic field at each of the receivers, and CT1(ω) and CT2(ω) account for any transmitter moment variations.
By following the standard procedure of taking the ratio of the far-receiver measurement to the near-receiver measurement, the response for each transmitter, H*CT1(ω) and H*CT2(ω) may be represented mathematically, for example, as follows:
The system noise (error) in both amplitude and phase as measured by the compensating transmitters may then be represented as the square root of the ratio of H*CT1(ω) to H*CT2(ω). This may be represented mathematically, for example, as follows:
where the attenuation error is AE=AR2(ω)/AR1(ω) and the phase error is ΔφE=ΔφR2−ΔφR1.
Based on Equations 3 and 4, the amplitude and phase error can be readily obtained from the compensating transmitter CT1 and CT2 firings. For example, with further reference now to
ΔφT1=ΔφF+ΔφE and ΔφCT2=ΔφF−ΔφE Equation 5
A
CT1(dB)=AF(dB)+AE(dB) and ACT2(dB)=AF(dB)−AE(dB) Equation 6
where ΔφCT1 and ΔφCT2 represent the measured phase shifts for each compensating transmitter firing, ACT1(dB) and ACT2(dB) represent the measured attenuation in units of decibels for each compensating transmitter firing, ΔφF and AF(dB) represent the phase shift and attenuation (in decibels) in the absence of error, and ΔφE and AE(dB) represent the phase shift and attenuation (in decibels) errors. The phase shift and attenuation errors may be computed from the measured phase shift and attenuation at 206, for example, as follows:
Although the compensating transmitters CT1 and CT2 have much shorter spacing than transmitters T1, T2, and T3, the attenuation and phase errors tend to be essentially the same since these errors are primarily caused by the receiving antennae and their corresponding electronics. Therefore, the phase and attenuation errors obtained in Equations 7 and 8 via the firing of the compensating transmitters CT1 and CT2 may be removed (subtracted) from uncompensated measurements to obtain compensated measurements. For example, uncompensated measurements may be obtained via sequentially firing transmitters T1, T2, and T3 of resistivity tool 100 at 208 and receiving the corresponding electromagnetic waves at receivers R1 and R2. These received waves may be processed at 210 to obtain measured phase shift and attenuation between the receivers R1 and R2 for each transmitter firing. The phase and attenuation errors obtained in 206 (e.g., via equations 7 and 8) may then be subtracted from the uncompensated measurements obtained in 210 to obtain compensated measurements at 212, for example, as follows:
ΔφC1=ΔφT1−ΔφE and AC1(dB)=AT1(dB)−AE(dB)
ΔφC2=ΔφT2−ΔφE and AC2(dB)=AT2(dB)−AE(dB)
ΔφC3=ΔφT3−ΔφE and AC3(dB)=AT3(dB)−AE(dB) Equation 9
where ΔφC1, ΔφC2, ΔφC3, AC1(dB), AC2(dB), and AC3(dB) represent the compensated phase and attenuation measurements obtained in accordance with exemplary embodiments of the present invention and ΔφT1, ΔφT2, ΔφT3, AT1(dB), AT2(dB), and AT3(dB) represent the uncompensated phase and attenuation measurements obtained from firing the asymmetric transmitters T1, T2, and T3.
The above described apparatus and method advantageously tend to provide for accurate error compensation. In particular, the methodology tends to be relatively insensitive to the positioning of the compensating transmitters CT1 and CT2. While a symmetric configuration is preferred, errors in placement or tool body deformation due to the extreme borehole temperature and pressure encountered downhole advantageously tend not to significantly affect the measured phase and attenuation errors. This is because the errors that result from such positional uncertainty tend to cancel out. Those of skill in the art will appreciate that the phase errors are obtained by subtraction in Equations 7 and 8. Therefore, further errors caused by a position change in the first compensating transmitter tend cancel those caused by a position change in the second compensating transmitter. This represents a significant improvement over the '842 patent described above.
With reference again to
A suitable controller may also optionally include other controllable components, such as sensors, data storage devices, power supplies, timers, and the like. The controller may also be disposed to be in electronic communication with various other sensors and/or probes for monitoring physical parameters of the borehole, such as a gamma ray sensor, a depth detection sensor, or an accelerometer, gyro or magnetometer to detect azimuth and inclination. A controller may also optionally communicate with other instruments in the drill string, such as telemetry systems that communicate with the surface. A controller may further optionally include volatile or non-volatile memory or a data storage device.
A suitable controller typically also includes conventional electronics utilized in transmitting and/or receiving an electromagnetic waveform. For example, the controller may include conventional electronics such as a variable gain amplifier for amplifying a relatively weak return signal (as compared to the transmitted signal) and/or various filters (e.g., low, high, and/or band pass filters), rectifiers, multiplexers, and other circuit components for processing the return signal. A suitable controller also typically includes conventional electronics for determining the amplitude and phase of a received electromagnetic wave as well as the attenuation and phase change between the first and second receivers. Such electronic systems are well known and conventional in the art.
Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims.