Acoustic Logging Tool

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority and benefit from U.S. Provisional Ser. No. 63/686,745 filed on Aug. 24, 2024, entitled “Acoustic Logging Tool,” the content of which is incorporated in its entirety herein by reference.

BACKGROUND OF THE INVENTION

Technical Field

The present disclosure generally relates to systems, devices and methods for acoustic logging downhole in an oil well. The acoustic logging tools disclosed herein may have application in a variety of logging operations, including for example, Cement Bond Logging.

Discussion of the Background

Applications of acoustic wave logging in the oil and gas industry includes surface, formation, and wellbore investigations of geophysics and wellbore conditions. Downhole wellbore operations which include completions, production and eventual abandonment typically begin with setting a string of casing or pipe into a drilled well bore followed by forcing cement into the annulus between the casing and the wellbore. Cementing serves to separate strata of the oil and gas bearing formation as well as prevent contamination from water containing zones. Various types of cement failures may include an absence or inadequate cement behind the casing or a failure to bond to the casing and formation, either of which can lead to fluid migration between zones.

Acoustic logging has application in evaluating the quality and completeness of the cement bond. The technique entails lowering an acoustic signal generating and receiving tool into the wellbore in a prescribed manner to investigate the cement behind a thick casing wall.

A typical Cement Bond Logging Tool (CBLT) 100 is shown in FIG. 1. Tool 100 is lowered into a wellbore via a wireline cable 112 which provides connectivity to surface electronics 114 and is positioned within wellbore casing 102 surrounded by cement 104 that fills the annulus between casing 102 and formation 106. The typical acoustic logging tool 100 includes one or more acoustic (or ultrasonic) transmitter transducers 120 designed to transmit an acoustic pulse and one or more acoustic receiver transducers 130 that collect returning acoustic signals. Transmitter 120 and receiver 130 sections are typically incorporated in the body (or sonde) 110 of the tool at specific intervals along its length and connected by spacers, connectors or subs. In a standard configuration, logging tool 100 determines the casing bond integrity by measuring the amplitude of the first arrival at a first receiver 130 located at a distance of 3 feet down hole from transmitter 120 while a deeper investigating second receiver 130 positioned at 5 feet collects a different time arrival and provides additional data.

In general, the acoustic signal may take a number of paths or a combination of paths. Transmitter 120's signal may travel down the tool itself; through the fluid; along the steel casing; into the cement annulus surrounding the casing, as well as into the formation. The signal reflects at one or more of those locations and mediums and returns to a receiver 130 with the measured amplitude being a key metric for determining a number of characteristics of the wellbore and its surroundings. For example, a higher return amplitude may be indicative a weak (or poor) casing and cement bond whereas a weaker amplitude caused by higher impedance at the casing-cement interface may indicate a cement bond of good (or better) integrity, etc. To minimize direct signal transfer from transmitter 120 to receiver 130, a sound deadening or isolator device 140 is located in line with the sonde body 110 and in between the transmitter section 120 and receiver section(s) 130 to attenuate (or delay) direct transducer signal noise in the receiver collected data.

Typically, control electronics 150 are housed in a pressure isolating housing 155 at the top of tool 100. Various connector subs or spacers 160 are located between sections to provide the prescribed spacing and to house conductor cable(s) and wires for transmission of data uphole. Segmented CBLTs may include additional transmitter and receiver sections located downhole from those shown and repeat the 3-5 foot spacing.

Current devices as the above and the systems and methods associated with tools of this design suffer from several limitations and drawbacks. These include poor signal to noise ratio in the acoustic signal collected by the receivers. The data transmitted uphole to the surface electronics and processing system is often difficult to separate from acoustic output signals coming from the transmitter. Also, existing tool designs have a narrow optimum deployment speed range that is limited primarily by the spacing of transmitter and receiver sections and the ability to record and adequately process the signals for a given spacing and speed. Further, existing tools suffer from high overall tool length that adds to lubricator requirements at the wellhead which complicates overall wireline deployment of the logging tool. Thus, improved logging tools, systems and methods are needed to improve the signal quality, reduce the length of the overall tool, and increase the speed and efficiency of data logging and collection.

SUMMARY OF EXEMPLARY EMBODIMENTS OF THE INVENTION

In one exemplary embodiment of the invention, an acoustic logging tool for conducting investigations in a wellbore comprises an acoustic transmitter disposed on an upper end of the tool; a transmitter electronics section disposed on an upper end of the tool and in communication with the transmitter; a sound isolating attenuator disposed on the tool downhole from the acoustic transmitter; a first receiver disposed on the tool downhole from the sound isolating attenuator; a second receiver disposed on the tool downhole from the first receiver; a receiver electronics section separate from the transmitter electronics section; and the receiver electronics section is also disposed on the tool downhole from the sound isolating attenuator and adjacent at least one of the receivers.

In another exemplary embodiment of the apparatus, An acoustic logging tool for conducting investigations in a wellbore comprises an acoustic transmitter disposed on an upper end of the tool; a transmitter electronics section disposed on an upper end of the tool and in communication with the transmitter; a sound isolating attenuator disposed on the tool downhole from the acoustic transmitter; a first receiver disposed on the tool downhole from the sound isolating attenuator; a second receiver disposed on the tool a downhole from the first receiver; a receiver electronics section separate from the transmitter electronics section disposed downhole from the sound isolating attenuator; and the total length of the acoustic logging tool is less than 95 inches.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute a part of the specification, illustrate one or more embodiments and, together with the description, explain these embodiments. In the drawings:

FIG. 1 shows a view of a prior art logging tool.

FIG. 2 shows an exemplary acoustic logging tool according to the present invention.

FIG. 3 shows an exemplary schematic diagram of the signal handling circuits of the acoustic logging tool.

FIG. 4 shows another exemplary schematic of the controller boards of the acoustic logging tool.

FIG. 6 shows a diagram of certain signal processing depending on signal paths.

FIGS. 6A and 6B show two alternative embodiments of the acoustic logging tool.

DETAILED DESCRIPTION OF EXAMPLES OF THE INVENTION

The following description of the embodiments refers to the accompanying drawings. The same reference numbers in different drawings identify the same or similar elements. The following detailed description is intended to provide an exemplary description of devices, systems and methods but does not limit the invention. Instead, the scope of the invention is defined by the appended claims. The following embodiments are discussed, for simplicity, with regard to devices, systems and methods to acoustically investigate a wellbore with particular emphasis on cased hole cement bond tools and methods, but such disclosure finds application to other acoustic logging approaches including open hole logging and others.

Reference throughout the specification to “one embodiment” or “an embodiment” means that a particular feature, structure or characteristic described in connection with an embodiment is included in at least one embodiment of the subject matter disclosed. Thus, the appearance of the phrases “in one embodiment” or “in an embodiment” in various places throughout the specification is not necessarily referring to the same embodiment. The drawings are intended to be illustrative of the claimed features and unless stated otherwise are not to scale. Where a dimension of a given feature may be pertinent, the detailed description will indicate one or more examples of the range and units of said dimension where needed to enable the subject matter. Further, the described features, structures or characteristics may be combined in any suitable manner in one or more embodiments.

In the context of the foregoing description, certain terms such as “uphole”, “upward” or “above” will generally denote a spatial or relative location in the direction proximal the surface of the well. Similarly, “lower”, “downhole”, “downward” etc. may refer to the general direction distal the wellbore point of entry at the ground level (or seabed). Further, where a wellbore deviates horizontally, the same terms may be used in the context of a location distal or proximal relative to the wellbore point of entry. Thus, in reference to a relative location of components of the tool or tools described herein, the terms uphole or downhole shall refer to a position above or below a particular point of reference on the tool, respectively. Similarly, the term “adjacent” when used in reference to a relative location of components on the tool or tools described herein shall mean the next component either above (uphole) or below (downhole) another component excluding any mechanical connector, such as a sub or spacer. For example, the phrase “the receiver electronics section is adjacent a receiver” shall encompass a receiver electronics section connected directly to the receiver itself or indirectly connected to the receiver through use of a connector such as a two-sided threaded sub or spacer located between the receiver electronics section and the receiver. The term or phrase “on the tool” as used herein shall refer to any of various components associated with, incorporated into, attached to other components upon or in-line as a part of an acoustic tool which in combination comprises an elongated acoustic sonde tool.

An exemplary acoustic logging tool with improved characteristics is illustrated as a Cement Bond Logging Tool (CBLT) in FIG. 2. For simplicity, CBLT 200 is shown as the tool alone, but it is to be understood that tool 200 may be installed in a cased or an open wellbore via wireline 112 that provides connectivity to surface electronics and controls 114 for investigating the integrity of the cement annulus and/or the formation geology (not shown) or other parameters.

In this example, tool 200 is comprised of an elongated cylindrical body or sonde 210 with an upper end oriented in the uphole direction and a lower end downhole. Sonde 210 may be comprised of various sections coupled together directly via threaded connection or spaced apart by connector subs or spacers 270. Sections include a transmitter electronics section 250 disposed uphole comprising signal actuating (fire) electronics and a power supply followed by a transmitter transducer 220 then by an isolator-sound attenuator section 240. Note that in this context the terms “acoustic transmitter transducer”, “transmitter”, and “acoustic transducer” or other similar term may be used interchangeably to refer to a device that emits an acoustic signal of one, or more than one, or a range of frequencies.

Distal to sound isolator 240, a first receiver section 230 is located in this example at 3 feet from transmitter 220 and a second receiver section 232 at 5 feet from the transmitter 220. In the tool 200 example shown, the 3-foot and 5-foot (i.e., “3′/5′” or “3-5 ft” or “3 ft-5 ft”) receiver spacing is utilized. However, though current typical cement bond logging tool (CBLT) configurations typically include a transmitter with two receivers spaced at 3 foot and 5 foot distances operating at 20KHz., different spacings, receiver types and different operating frequencies are contemplatable by those skilled in the art having the benefit of the present disclosure. For example, receiver sections 230/232 may be comprised of one or a combination of receiver types of various spacing configurations; including but not limited to, one or more single receivers, a multi-receiver such as a segmented or radial receiver, operating as either as a mono or uni-directional or omni-directional receiver. For example, an 8-radial receiver section may be spaced 1.5 foot away from the transmitter, and a standard circumferential receiver at 3 foot spacing and another positioned at 5 foot spacing away from the transmitter 220. Other configurations include a radial receiver at 3 foot spacing from the transmitter and a second radial or standard receiver at 5 foot spacing. A 3 foot radial receiver may also include 8 radial receivers processed separately or added together with the mean determined by adding all the radial receiver signals together and dividing by eight resulting in a single signal output.

In one preferred embodiment, receiver electronics section 260 is disposed within a pressure isolating housing 265 which is positioned in between receiver sections 230/232. Positioning the receiver control electronics into a housing downhole from the transmitter and adjacent one or more receiver sections, allows the electronics and hence signal quality to become less affected by direct arrivals from the transmitter(s). Additionally, by utilizing a section of tool typically taken up by a spacer and/or sub, the overall length of the tool may be reduced and result in a cost savings. This is owing to the fact that when the tool is inserted into a well head, pressure lubricators (tubing) are used to couple the tool to the top of the wellhead. These pieces of lubricator typically come in specific lengths (e.g., 10-foot) and if the required length is reduced such that even if a single length of lubricator is eliminated; a significant cost savings may be realized. For example, a current standard 3 ft-5 ft CBLT is approximately 105″ long, but by moving all or a portion of the control elements of the electronics into the unused housing between the receiver elements, the overall length may be decreased by about a foot (12 inches) to result in a tool of approximately 93″ in length.

The amplitude and travel time (i.e., the time of travel from the origination of the sound pulse to the received pulse) of the signal received by the multiple receiver elements is a critical measurement, yielding valuable information to the log analyst. Typically, these individual signals are handled by individual measurement circuits and are time multiplexed to the output of the device. In operation, the logging tool is moved through the wellbore at a prescribed speed and the travel time of the signals is adjusted to positionally account for the translation speed of the tool through the wellbore.

Consequently, in order to avoid introducing time distortions into the measurements, the allowable speed must fall within a certain recommended range, for example approximately 30 ft/min.

It is a further aspect of the present invention that dedicated receiver signal handling circuits (see FIGS. 3 and 4) may be included within housing 265 for each receiver 230/232, thus allowing for the signals from the various receivers to be captured and processed at substantially the same time as their arrival thus eliminating or minimizing the effect of the direct arrival signal coming from transmitter 220. The signals may then be stored and processed locally (i.e., at 260 and within 265) which may include time shifting to account for their lengthwise location within the tool and wellbore. The shifted data may then be subsequently transmitted uphole via wireline 112 to the surface electronics 114 for additional processing. Thus, in this manner, tool 200 minimizes direct signal contamination from transmitter 220, while also receiving and processing the receiver signals at substantially the same time resulting in better signal fidelity and definition for logging analysis even at higher tool speeds.

Transmitting large amounts of data (digital or analog) up the wireline 112 is a challenge, as the wireline conductor typically has a limited data handling capacity. This limitation is made more difficult as the line length increases with lengthier horizontal wells. It is thus a further aspect of the present acoustic tool 200, that as the acoustic transmitter 220 is fired at a constant rate, a limited amount of data is transmitted up the wireline 112 upon each transmitter firing. However, as logging speeds increase, the vertical resolution (density of date per unit time) of the measured data is also increasing which can result in deterioration in signal quality that the signal processing methodology is unable to compensate for. In the present invention, since the data may be captured from all the receivers at the transmitter firing by the proximally located receiver electronics section 260, the individual receiver signals 230/232 may be sequentially transmitted up the wireline 112 at some predetermined rate and/or time delay depending upon available data transmission availability. In this manner, all the data of a single frame of data (transmitter firing and receiver arrival) is captured at the same time and place in the wellbore. In contrast to existing technology whereby data is captured at different times and depths and subsequently sent up; the present invention conveys enhanced signal quality even at higher transmission rates and higher tool deployment speeds. Thus, the electronics arrangements disclosed herein allow the logging tool to run at higher translation speeds, including speeds that may exceed the 30 ft/min, for example 40 ft/min or greater, while maintaining data integrity.

FIG. 3 shows an exemplary schematic diagram of a control system for employing and operating the acoustic tool of the present disclosure. Attention is also directed to FIG. 2 for relative locations of the system's components within acoustic tool 200. Within transmitter electronics section 250, the circuitry to fire transmitter 220 may include an amplifier 282 which receives a fire signal from a power supply 284 controlled by processor 286. In certain preferred embodiments, a central controller 288 acts as a master controller for both transmitter controller 286 and receivers'230/232 circuitry and may be located uphole of the receivers or in alternative embodiments, is included downhole within receiver electronics section 260.

In preferred embodiments, receiver control electronics 260 housed within pressure isolating housing 265 includes a signal amplifier 293/294 for each receiver which in turn provides the individual signals to analog to digital convertors (ADC) 295/296 for conveyance uphole via central controller 288. Electronic amplifier circuit or line driver 290 powered by supply 292 then drives the combined signal load uphole via wireline 112 as the transmission line to the surface electronics 114 (see, FIG. 2).

Another depiction of the arrangement and method of operation of the electronics of an embodiment of the present invention is shown in FIG. 4. As mentioned, it is an object of the present invention to capture and process receiver signals at a location shielded or less subject to direct transmitter interference. As shown, various microprocessor boards may be included. Note that the steps shown in FIG. 4 may mirror the actions of one or more of the controller boards as represented in FIG. 3. Thus, the steps discussed here are for exemplary purposes only as fewer or additional steps and boards may be included. For example, a receiver board 460; a timing board 480; a filtering board 470, and a logic board 490 may be located below isolator attenuator 240. In certain embodiments these components interact via a shared common conductor 420 that supplies power and/or data transmission from the surface 114 to distal locations 415 further down the length of tool 200. Other boards, including for example, a power supply board 430 to power other boards; a transmitter board 440 to fire the transmitter 250, and a pulse board 450 are located uphole above isolator attenuator 240. In this example, surface power 114 is fed to common conductor 420 for logging tool 200 at 120-130 volts. The low voltage power supply board 430 converts and distributes the 120 volts to other downhole boards, which may include board 440 for firing electronics 250 that controls transmitter(s) 220. A separate pulse board 450 may collect pulses from the tool and may be located above or below sound isolator 240. Receiver electronics section 260 which is located within pressure isolating housing 265 and below (downhole) from sound isolator 240 may include one or more receiver board(s) 460 to collect incoming signal sorted by a timing board 480. Other exemplary steps and functions of electronics section 260 may include, but are not limited to, a filter board 470 to reduce background noise, and a logic board 490 to transmit the data uphole to surface equipment.

An exemplary data collecting and processing method which accounts for various signal pathways captured by tool 200 is illustrated in FIG. 5. As discussed prior, when the transmitter 220 is fired by fire electronics 250, the transmitted signal may undertake various signal pathways which, depending on the length of travel, the medium and other factors; the signal received at one or both receivers 230/232 may be greatly diminished. For example, the received signal may be reduced by a factor of 10 or greater with traditional logging tools and methods. Also, in current tools of this type, the signal is further diminished due its being relayed a distance uphole to a central electronics section (e.g. 150 of FIG. 1) well above the actual signal receiving location due to line noise and other sources of interference. This loss in fidelity is further exacerbated by sequential transmission of data packets due to data rate transfer limitations discussed prior. In the present arrangement, the pairs of receivers'230/232 data (510/520, respectively) is gathered and recorded substantially at the same time prior to the recording of other signal paths, e.g., 530 (direct casing), 540 (through the tool), or 550 (through the fluid), among others.

Alternative embodiments of logging tool 200 are shown in FIGS. 6A and 6B, also preserve the advantages of data storage and processing adjacent at least one of receivers 230 and 232. In these examples, receiver electronics section 260 may be positioned adjacent and above receiver 230 (FIG. 6A) or adjacent and below receiver 232 (FIG. 6B). In these cases, a spacer 270 appropriately sized to maintain a 3 ft-5 ft spacing may be included.

In addition to a higher S/N ratio, this arrangement of tool 200 imparts certain processing advantages and efficiencies, as well. For example, in current tools and methods, due to data transfer limitations, the receiver signals are typically aggregated and amplified electronically via gain, whereas in the current arrangement each signal is independently optimized for gain prior to transmission starting from higher signal strength as discussed above, thus requiring less gain.