Patent Publication Number: US-8117907-B2

Title: Caliper logging using circumferentially spaced and/or angled transducer elements

Description:
FIELD OF THE INVENTION 
     The present invention relates generally to a downhole tool for making standoff and caliper measurements. More particularly, exemplary embodiments of the invention relate to a downhole tool having at least one angled ultrasonic transducer. Another exemplary embodiment of the invention relates to a standoff sensor including at least first, second, and third transducer elements. 
     BACKGROUND OF THE INVENTION 
     Logging while drilling (LWD) techniques are well-known in the downhole drilling industry and are commonly used to measure various formation properties during drilling. Such LWD techniques include, for example, natural gamma ray, spectral density, neutron density, inductive and galvanic resistivity, acoustic velocity, and the like. Many such LWD techniques require that the standoff distance between the various logging sensors in the drill string and the borehole wall be known with a reasonable degree of accuracy. For example, LWD nuclear/neutron measurements utilize the standoff distance in the count rate weighting to correct formation density and porosity data. Moreover, the shape of the borehole (in addition to the standoff distances) is known to influence logging measurements. 
     Ultrasonic standoff measurements and/or ultrasonic caliper logging measurements are commonly utilized during drilling to determine standoff distance and therefore constitute an important downhole measurement. Ultrasonic caliper logging measurements are also commonly used to measure borehole size, shape, and the position of the drill string within the borehole. Conventionally, ultrasonic standoff and/or caliper measurements typically include transmitting an ultrasonic pulse into the drilling fluid and receiving the portion of the ultrasonic energy that is reflected back to the receiver from the drilling fluid borehole wall interface. The standoff distance is then typically determined from the ultrasonic velocity of the drilling fluid and the time delay between transmission and reception of the ultrasonic energy. 
     Caliper logging measurements are typically made with a plurality of ultrasonic sensors (typically two or three). Various sensor arrangements are known in the art. For example, caliper LWD tools employing three sensors spaced equi-angularly about a circumference of the drill collar are commonly utilized. Caliper LWD tools employing only two sensors are also known. For example, in one two-sensor caliper logging tool, the sensors are deployed on opposite sides of the drill collar (i.e., they are diametrically opposed). In another two-sensor caliper logging tool, the sensors are axially spaced, but deployed at the same tool face. 
     The above described prior art caliper LWD tools commonly employ either pulse echo ultrasonic sensors or pitch-catch ultrasonic sensors. A pulse echo ultrasonic sensor emits (transmits) ultrasonic waves and receives the reflected signal using the same transducer element. Pulse echo sensors are typically less complex and therefore less expensive to utilize. Pitch catch sensors typically include two transducer elements; the first of which is used as a transmitter (i.e., to transmit ultrasonic waves) and the other of which is utilized as a receiver (i.e., to receive the reflected ultrasonic signal). Pitch catch ultrasonic sensors are known to advantageously reduce, or even eliminate, transducer ringing effects, by substantially electromechanically isolating the transmitter and receiver transducer elements. They therefore tend to exhibit an improved signal to noise ratio (as compared to pulse echo sensors). 
     The above described caliper logging tools generally work well (providing both accurate and reliable standoff determination) when the drill string is centered (or nearly centered) in a circular borehole. In such instances the transmitted wave is essentially normal to the borehole wall, which tends to maximize the reflection efficiency at the receiver. In many drilling operations (e.g., in horizontal or highly inclined wells) the drill string can be eccentered in the borehole. Moreover, in certain formation types the borehole may have an irregular (e.g., elliptical or oval) shape. In these operations the transmitted ultrasonic waves are sometimes incident on the borehole wall at a non-normal (oblique) angle, which can result in reduced ultrasonic energy at the receiver. In some cases there may be blind spots at which the reflected waves are undetected by the sensor. In such cases, a portion of the borehole wall is invisible to the standoff sensor. Since standoff measurements are essential to interpreting certain other LWD data, these blind spots can have significant negative consequences (e.g., especially in pay zone steering operations). 
     Therefore, there exists a need for an improved caliper LWD tool and/or a caliper tool utilizing improved standoff sensors, particularly for use in deviated (e.g., horizontal) well bores in which the drill string is commonly eccentered (e.g., on bottom). Such a tool and/or sensors may advantageously improve the reliability of caliper LWD measurements. 
     SUMMARY OF THE INVENTION 
     The present invention addresses one or more of the above-described drawbacks of prior art standoff measurement techniques and prior art drilling fluid ultrasonic velocity estimation techniques. One aspect of this invention includes a downhole measurement tool having at least one angled ultrasonic standoff sensors. Another aspect of the present invention includes a downhole standoff sensor having at least three circumferentially spaced piezoelectric transducer elements. At least a first element is configured for use in pulse echo mode and therefore both transmits and receives ultrasonic energy. At least second and third elements are configured to receive ultrasonic energy transmitted by the first element in pitch catch mode. An electronic controller is configured to determine a standoff distance from the ultrasonic waveforms received at the at least first, second, and third piezoelectric transducer elements. The controller may further be configured to estimate the eccentricity of a measurement tool in the borehole, for example, from a difference or ratio between the ultrasonic energy received at the second and third transducer elements. 
     Exemplary embodiments of the present invention advantageously provide several technical advantages. For example, exemplary embodiments of the invention may improve borehole coverage and data quality and reliability in LWD caliper logging. In particular, the invention may advantageously reduce or even eliminate the blind spots when logging eccentric bore holes. Since standoff measurements are critical to certain LWD data interpretation, the invention may further improve the quality and reliability of such LWD data. 
     In one aspect the present invention includes a downhole logging while drilling tool. The logging while drilling tool includes a substantially cylindrical tool body having a longitudinal axis and is configured to be connected with a drill string. At least one standoff sensor is deployed in the tool body. The standoff sensor is configured to both transmit ultrasonic energy into a borehole and receive reflected ultrasonic energy. The standoff sensor has a sensor axis which defines a direction of optimum signal transmission and reception. The sensor axis is orthogonal to the longitudinal axis of the tool body and is further oriented at a non-zero angle relative to a radial direction in the tool body. The logging while drilling tool further includes a controller including instructions for determining a standoff distance from the reflected ultrasonic energy received at the at least one standoff sensor. 
     In another aspect, this invention includes a downhole logging while drilling tool. The logging while drilling tool includes a substantially cylindrical tool body having a longitudinal axis and is configured to be connected with a drill string. The tool further includes at least first, second, and third circumferentially spaced piezoelectric transducer elements. At least a first of the transducer elements is configured to both transmit ultrasonic energy into a borehole and receive reflected ultrasonic energy. At least a second and a third of the transducer elements are configured to receive the reflected ultrasonic energy transmitted by the first transducer element. The logging while drilling tool further includes a controller having instructions for determining a single standoff distance from the reflected ultrasonic energy received at the first, second, and third transducer elements. 
     In still another aspect, this invention includes a method for estimating downhole an eccentricity of a logging drilling tool. The method includes deploying a downhole tool in a subterranean borehole, the tool including an ultrasonic standoff sensor having at least three circumferentially spaced piezoelectric transducer elements, at least a first of the transducer elements being configured to both transmit ultrasonic energy into a borehole and receive reflected ultrasonic energy, at least a second and a third of the transducer elements being configured to receive the reflected ultrasonic energy originally transmitted by the first transducer element. The method further includes causing the first transducer element to transmit ultrasonic energy into the borehole, causing at least the second and the third transducer elements to receive the ultrasonic energy transmitted by the first transducer element, and processing the received ultrasonic energy to estimate a degree of eccentricity of the downhole tool in the borehole. 
     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. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       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: 
         FIG. 1  is a schematic representation of an offshore oil and/or gas drilling platform utilizing an exemplary embodiment of the present invention. 
         FIG. 2  depicts one exemplary embodiment of the downhole tool shown on  FIG. 1 . 
         FIG. 3  depicts, in circular cross section, a prior art arrangement deployed in a borehole. 
         FIG. 4  depicts, in circular cross section, one exemplary embodiment of the present invention deployed in borehole. 
         FIGS. 5A and 5B  depict, in circular cross section, other exemplary embodiments of the invention. 
         FIG. 6  depicts, in circular cross section, still another exemplary embodiment of the invention. 
     
    
    
     DETAILED DESCRIPTION 
     Referring first to  FIGS. 1 through 6 , it will be understood that features or aspects of the embodiments illustrated may be shown from various views. Where such features or aspects are common to particular views, they are labeled using the same reference numeral. Thus, a feature or aspect labeled with a particular reference numeral on one view in  FIGS. 1 through 6  may be described herein with respect to that reference numeral shown on other views. It will all be appreciated that  FIGS. 1-6  are schematic in nature and are therefore not drawn to scale. 
       FIG. 1  depicts one exemplary embodiment of a logging while drilling tool  100  in accordance with the present invention in use in an offshore oil or gas drilling assembly, generally denoted  10 . In  FIG. 1 , a semisubmersible drilling platform  12  is positioned over an oil or gas formation (not shown) disposed below the sea floor  16 . A subsea conduit  18  extends from deck  20  of platform  12  to a wellhead installation  22 . The platform may include a derrick  26  and a hoisting apparatus  28  for raising and lowering the drill string  30 , which, as shown, extends into borehole  40  and includes a drill bit  32  and a logging while drilling tool  100  having an ultrasonic standoff sensor  120 . Drill string  30  may further include substantially any other downhole tools, including for example, a downhole drill motor, a mud pulse telemetry system, and one or more other sensors, such as a nuclear or sonic logging sensor, for sensing downhole characteristics of the borehole and the surrounding formation. 
     It will be understood by those of ordinary skill in the art that the measurement tool  100  of the present invention is not limited to use with a semisubmersible platform  12  as illustrated in  FIG. 1 . LWD tool  100  is equally well suited for use with any kind of subterranean drilling operation, either offshore or onshore. 
     Referring now to  FIG. 2 , one exemplary embodiment of LWD tool  100  according to the present invention is shown deployed in a subterranean borehole. LWD tool  100  includes at least one standoff sensor  120  deployed in the tool body (drill collar)  110 . In the exemplary embodiment shown, LWD tool  100  is configured as a measurement sub, including a substantially cylindrical tool collar  110  configured for coupling with a drill string (e.g., drill string  30  in  FIG. 1 ) and therefore typically, but not necessarily, includes threaded pin  74  and box  72  end portions. Through pipe  105  provides a conduit for the flow of drilling fluid downhole, for example, to a drill bit assembly (e.g., drill bit  32  in  FIG. 1 ). As is known to those of ordinary skill in the art, drilling fluid is typically pumped down through pipe  105  during drilling. It will be appreciated that LWD tool  100  may include other LWD sensors (not shown), for example, including one or more nuclear (gamma ray) density sensors. Such sensors when utilized may be advantageously circumferentially aligned with standoff sensor  120 . The invention is not limited in these regards. 
     With continued reference to  FIG. 2 , it will be appreciated that standoff sensor  120  may include substantially any known ultrasonic standoff sensors suitable for use in downhole tools. For example, sensor  120  may include conventional piezo-ceramic and/or piezo-composite transducer elements. Suitable piezo-composite transducers are disclosed, for example, in commonly assigned U.S. Pat. No. 7,036,363. Sensor  120  may also be configured to operate in pulse-echo mode, in which a single element is used as both the transmitter and receiver, or in a pitch-catch mode in which one element is used as a transmitter and a separate element is used as the receiver. Typically, a pulse-echo transducer may generate ring-down noise (the transducer once excited reverberates for a duration of time before an echo can be received and analyzed), which, unless properly damped or delayed, can overlap and interfere with the received waveform. Pitch-catch transducers tend to eliminate ring-down noise, and are generally preferred, provided that the cross-talk noise between the transmitter and receiver is sufficiently isolated and damped. 
     Although not shown on  FIG. 2 , it will be appreciated that LWD tools in accordance with this invention typically include an electronic controller. Such a controller typically includes conventional electrical drive voltage electronics (e.g., a high voltage power supply) for applying waveforms to the standoff sensor  120 . The controller typically also includes receiving electronics, such as a variable gain amplifier for amplifying the relatively weak return signal (as compared to the transmitted signal). The receiving electronics may also include various filters (e.g., pass band filters), rectifiers, multiplexers, and other circuit components for processing the return signal. 
     A suitable controller typically further includes a digital programmable processor such as a microprocessor or a microcontroller and processor-readable or computer-readable programming code embodying logic, including instructions for controlling the function of the tool. Substantially any suitable digital processor (or processors) may be utilized, for example, including an ADSP-2191M microprocessor, available from Analog Devices, Inc. The controller may be disposed, for example, to calculate a standoff distance between the sensor and a borehole wall based on the ultrasonic sensor measurements. A suitable controller may therefore include instructions for determining arrival times and amplitudes of various received waveform components and for solving various algorithms known to those of ordinary skill in the art. 
     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 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. The controller may also optionally communicate with other instruments in the drill string, such as telemetry systems that communicate with the surface. The controller may further optionally include volatile or non-volatile memory or a data storage device. The artisan of ordinary skill will readily recognize that the controller may be disposed elsewhere in the drill string (e.g., in another LWD tool or sub). 
       FIG. 3 , depicts in circular cross section, a prior art standoff measurement tool  50  deployed in a borehole. Prior art measurement tool  50  includes at least one standoff sensor  52  deployed on the tool body  51 . Those of ordinary skill in the art will readily recognize that embodiments including two or more standoff sensors deployed about the circumference of a downhole tool are also well known. Standoff sensor  52  is mounted conventionally in that the sensor axis  53  (the axis of maximum transmission and reception efficiency) lies in the circular plane and passes through the geometric center  54  of the tool. Stated another way, the sensor axis  53  of a conventionally mounted standoff sensor  52  is aligned with a radius of the tool  50 . Such mounting is referred to herein as “normally mounted.” 
     As also shown on  FIG. 3 , a conventionally mounted sensor  52  may not always be disposed to receive an obliquely reflected wave in a decentralized drill string. As shown (when the tool is decentralized) the transmitted ultrasonic waves  58  can be incident on the borehole wall  40  at a non-normal (oblique) angle, which can result in reduced energy at the receiver. In some cases there may be blind spots at which the reflected waves  59  go essentially undetected by the sensor. In such cases, a portion of the borehole wall is essentially invisible to the standoff sensor  52 . Since standoff measurements are essential to interpreting some other types of LWD data (as described above), these blind spots can have significant negative consequences (e.g., especially in pay zone steering operations). 
     With reference now to  FIG. 4 , LWD tool  100  in accordance with the present invention is shown (in circular cross section) deployed in a borehole. LWD tool  100  includes at least one angled standoff sensor  120  deployed in tool body  110 . Standoff sensor  120  is configured for use in pulse echo mode and is angled such that the sensor axis  122  is oriented at a non-zero angle θ with respect to the tool radius  115 . For example, in certain exemplary embodiments, the angle θ may be in a range from about 5 to about 30 degrees. An angled standoff sensor  120  transmits an ultrasonic wave  125  at an angle such that the wave is reflected  126  approximately normally from the borehole wall  40  and is therefore received back at the sensor  120  (as shown in the exemplary embodiment on  FIG. 4 ). It will be appreciated that LWD tool  100  may include multiple angled sensors. For example, in one exemplary embodiment, a standoff measurement tool in accordance with the invention includes three standoff sensors, at least two of which are angled, configured to minimize (or substantially eliminate) blind spots when the tool is eccentered in a borehole having a highly elliptical profile. 
     With reference now to  FIGS. 5A and 5B , standoff measurement tools  200 ,  200 ′ in accordance with the invention may also include angled standoff sensors configured for use in pitch catch mode. In the exemplary embodiments shown, measurement tools  200 ,  200 ′ include at least one normally mounted transmitter element  220  and a plurality of angled receiver elements  230 ,  240 . The transmitter  220  is typically configured to both transmit and receive ultrasonic energy in conventional pulse echo mode. Element  220  is also typically normally mounted in the tool body, although the invention is not limited in this regard. Receiver elements  230 ,  240  are typically angled in the same sense as standoff sensor  120  shown on  FIG. 4  (such that the sensor axis is oriented at a non-zero angle with respect to the tool radius). In use, transmitter  220  transmits ultrasonic energy  252  into the borehole annulus. The reflected waveform  254  may then be received at one or more of elements  220 ,  230 , and  240 . 
     In the exemplary embodiment  200  shown on  FIG. 5A , the transmitter  220  and receiver  230 ,  240  elements are deployed asymmetrically (e.g., both receivers are deployed on a common (the same) circumferential side of the transmitter). In such a configuration, the receiver  230  mounted in closer proximity to the transmitter  220  is typically angled less (e.g., an angle in the range from about 5 to about 20 degrees) than the receiver  240  that is more distant from the transmitter  220  (e.g., which may be angled in the range from about 15 to about 30 degrees). As depicted in the exemplary embodiment shown on  FIG. 5A , receiver elements  230 ,  240  are disposed to receive reflected waveform  254  when measurement tool  200  is eccentered in the borehole  40 . 
     In the exemplary embodiment  200 ′ shown on  FIG. 5B , the transmitter  220  and receiver  230 ,  240  elements are deployed symmetrically (e.g., receivers  230  and  240  are deployed on opposite circumferential sides of the transmitter  220 ). In such a configuration, the receivers  230 ,  240  are typically mounted at substantially the same angle (e.g., in the range from about 5 to about 30 degrees). Symmetric embodiments such as that shown on  FIG. 5B , tend to advantageously best eliminate blind spots irrespective of the degree of borehole eccentricity. 
     It will be appreciated that downhole tools  200  and  200 ′ are not limited to embodiments including three transmitter and receiver elements. Alternative embodiments may include, for example, four, five, six, or even seven transmitter and/or receiver elements. 
     With reference now to  FIG. 6 , another exemplary embodiment  300  in accordance with the invention is depicted in circular cross section. In the exemplary embodiment shown, measurement tool  300  includes at least one ultrasonic sensor  320  deployed in a tool body  310 . Sensor  320  includes at least three piezoelectric transducer elements  322 ,  324 ,  326  and operates in both pulse echo mode and pitch catch mode as described in more detail below. While the exemplary embodiment shown includes only a single sensor  320 , it will be appreciated that measurement tool  300  may include additional ultrasonic sensors circumferentially or axially spaced from sensor  320  (for example two or three of ultrasonic sensors  320 ). Those of ordinary skill in the art will readily recognize that sensor  320  may further include conventional barrier layer(s), impedance matching layer(s), and/or attenuating backing layer(s), which are not shown in  FIG. 6 . The invention is not limited in these regards. It will also be appreciated that sensor  320  is not drawn to scale in  FIG. 6 . 
     Piezoelectric transducer elements  322 ,  324 , and  326  are mounted in a sensor housing  330 , which is further mounted in the tool body  310 . Piezoelectric transducer element  322  is preferably normally mounted (as described above with respect to sensor  52  in  FIG. 3 ). Transducer element  322  is further configured to both transmit and receive ultrasonic waves in a pulse echo mode. Transducer elements  324  and  326  are configured to receive ultrasonic waves from the borehole in pitch catch mode. In the exemplary embodiment shown, transducers  324  and  326  are deployed such that the transducer axes are parallel with the axis of element  322 . The invention is not limited in this regard, however, as transducer elements  324  and  326  may also be angled relative to transducer element  322 , for example, depending on expected operating conditions such as standoff values, borehole shape, and tool position in the borehole. 
     It will be appreciated that the invention is not limited to sensor embodiments having three transducer (transmitter and receiver) elements. Additional transducer elements may be utilized. For example, alternative sensor embodiments may include four, five, six, and even seven transducer elements. The invention is not limited in this regard, so long as the sensor includes at least three transducer elements. The invention is also not limited to embodiments having a central transducer element (e.g., element  322 ) and outer receiver elements (e.g., elements  324  and  326 ). Nor is the invention limited to embodiments in which only a single element transmits ultrasonic energy. 
     With continued reference to  FIG. 6 , one of the receivers (e.g., transducer element  324  in the exemplary embodiment shown on  FIG. 6 ) typically receive a stronger signal than the other receiver (transducer element  326  in the exemplary embodiment shown) when the measurement tool  300  is eccentered in a borehole  40 . It will be appreciated that when the measurement tool  300  is eccentered in the opposite direction that the other receiver (transducer element  326 ) tends to receive the stronger signal. When the measurement tool  300  is approximately centered in the borehole  40 , the angle of incidence of the transmitted ultrasonic wave is nearly normal to the borehole wall  40  such that transducer element  322  tends to receive the strongest signal, while receivers  324  and  326  tend to receive relatively weaker signals. 
     Measurement tool  300  further includes a controller configured to calculate a standoff distance from the reflected waveforms received at transducer elements  322 ,  324 , and  326 . The controller may be further configured to estimate tool eccentricity in the borehole from the reflected waveforms received at transducer elements  322 ,  324 , and  326 . When the tool is centered in the borehole, the reflected ultrasonic energy tends to be approximately symmetric about the transducer element  322  such that elements  324  and  326  received approximately the same ultrasonic energy. When the tool is eccentered in the borehole, the reflected ultrasonic energy is asymmetric about transducer element  322  such that one of the elements  324  and  326  receives more energy than the other. In such a scenario, the degree of eccentricity may be estimated based on the difference (or the normalized difference or the ratio) of the ultrasonic energy received at elements  324  and  326 . In general, an increasing difference or ratio (indicating a more asymmetric reflected signal) indicates a greater eccentricity. By combining such measurements with a conventional tool face measurement, the direction of the eccentricity may also be estimated. 
     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.