WO2012068205A2 - Method and apparatus for determining the size of a borehole - Google Patents

Abstract

The present application discloses an apparatus and method for determining the diameter of a borehole. The method includes disposing an acoustic tool at a first depth in a borehole. The acoustic tool may include a source and a receiver. The source of the acoustic tool may generate a plurality of waves at a first depth of the borehole. The waves may include at least one of a compressional wave and a refracted shear wave. The receiver of the acoustic tool may receive a wave and at least one of a velocity and an arrival time of the wave may be determined. Additionally, a velocity of drilling mud surrounding the acoustic tool may also be determined. Using on one or more of the velocity, the arrival time, the mud velocity, an acoustic tool dimension, and a distance between the source and the receiver, a diameter of the borehole may be determined.

Description

METHOD AND APPARATUS FOR DETERMINING THE SIZE OF A BOREHOLE

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application No. 61/414,205, which was filed November 16, 2010 and is hereby incorporated by reference in its entirety.

BACKGROUND

The present disclosure relates generally to well logging and measurement in subterranean formations and, more particularly, the present disclosure relates to a system and method for determining the size of a borehole.

To ease the process of drilling into a formation and to improve production yields for desirable formation fluids, the oilfield-services industry has developed processes and tools for measuring downhole properties. One such downhole property is the size of the borehole generated by drilling operations, and one of the many instruments that may be employed is a borehole caliper. The caliper measures the borehole size or architecture and/or the logging tool's position in the borehole. Such parameters are important as they may be required by regulatory bodies and may be used to compensate other instruments' measurements. Existing calipers, however, are subject to mechanical failures and are unreliable for boreholes with a diameter larger than approximately 14 3/4 inches. What is needed is a reliable borehole measurement system that determines the borehole size of a larger range of borehole sizes, even large boreholes on the order of 20 inches in diameter.

FIGURES

Some specific exemplary embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings.

Figure 1 illustrates a well with an example logging system.

Figures 2a and 2b illustrates an example acoustic measurement system.

Figure 3 depicts an example of field data, in accordance with certain embodiments of the present disclosure.

Figure. 4 depicts example log data (inputs) for an HSI graph, in accordance with certain embodiments of the present disclosure.

While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.

DETAILED DESCRIPTION

The present disclosure relates generally to logging and measurement tools used in subterranean formations and, more particularly, the present disclosure relates to a system and method for determining the size of a borehole.

For the purposes of this disclosure, an information handling system may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. The information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display. The information handling system may also include one or more buses operable to transmit communications between the various hardware components,

For the purposes of this disclosure, computer-readable media may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Computer-readable media may include, for example without limitation, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing

Illustrative embodiments are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.

To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells as well as production wells, including hydrocarbon wells.

Modern petroleum drilling and production operations demand information relating to parameters and conditions downhole. Several methods exist for downhole information collecting ("logging"), including conventional wireline logging and logging while drilling ("LWD"). In conventional wireline logging, a probe ("sonde") is lowered into the borehole after some or all of the well has been drilled. In LWD, data is typically collected during the drilling process, thereby avoiding any need to remove the drilling assembly to insert a wireline logging tool. LWD consequently allows the driller to make accurate real-time modifications or corrections to optimize performance while minimizing down time. "Measurement-while-drilling" (MWD) is the term for measuring conditions downhole concerning the movement and location of the drilling assembly while the drilling continues. "Logging-while-drilling" (LWD) is the term for similar techniques that concentrate more on formation parameter measurement. While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For the purposes of this disclosure, the term LWD will be used with the understanding that this term encompasses both the collection of formation parameters and the collection of information relating to the movement and position of the drilling assembly

Figure 1 illustrates an example drilling system 1 10 incorporating aspects of the present disclosure for measuring and determining the size of borehole 101. To extract fluid from the formation 100, a borehole 101 may be drilled in the formation 100 using the drilling system 1 10. The formation 100 may contain a deposit of desirable fluid such as oil or natural gas. In the example drilling system 1 10 shown in FIG. 1 , a drilling rig 1 1 1 may be coupled to a drill string 1 12, which in turn couples to a drill bit 1 13. As used herein, a drill string is defined as including drill pipe 1 14, one or more drill collars 1 15, and a drill bit 1 13. The term "couple" or "couples" used herein is intended to mean either an indirect or direct connection. Thus, if a first device "couples" to a second device, that connection may be through a direct connection or through an indirect connection via other devices or connectors. Drill string 112 may include a rotary-steerable system (not shown) that drives the action of drill bit 113 from the surface. The action of drill bit 113 gradually wears away the formation, creating and extending borehole 101. As the depth of borehole 101 increases, drill operators add additional drill pipe and/or drill collar segments to drill string 1 12, allowing drill bit 113 to progress farther into formation 100.

The drilling system 110 may also include one or more processors or information handling systems containing processors. For example, control unit 160 may include a processor to analyze data received at a downhole measurement tool. Although Fig. 1 shows control unit 160 with the processor at a surface location, a separate control unit and processor may be located inside well 101, or it may be located at or near the sea floor if drilling occurs underwater. For example, a control unit with a processor may be located inside drill bit 113 or in drill string 112. In other embodiments, the drilling system may include multiple processors, one of which is located in drill bit 113 or elsewhere in the drill string along with data storage equipment.

The embodiment shown in Fig. 1 includes example transducers 120 disposed on an outer surface of drill collar 1 15. The transducers 120 may emit energy into the formation. In certain embodiments, the energy may be in the form of sonic waves or acoustic pulses. The transducers may be coupled to a telemetry transmitter (not shown) in the drill string that communicates with the surface, providing telemetry signals and receiving command signals for example, over wireline 130. In alternative embodiments, a wireless transmission may be used to transmit the telemetry signal. A surface transceiver at the control unit 160 may be configured to receive transmitted telemetry signals and to transmit command signals downhole. Alternatively, the surface transceiver may be coupled to another portion of the rigging or to drillstring. One or more repeater modules (not shown) may be provided along the drill string to receive and retransmit the telemetry and command signals. The surface transceiver may be coupled to a logging facility that may gather, store, process, and analyze the telemetry information

In certain embodiments, the transducers 120 may be arranged in an array as part of a downhole acoustic caliper. In certain embodiments, the downhole acoustic caliper may be incorporated into a downhole sub included in drill string 1 12. The transducers 120 may be piezoelectric transducers configured to transmit acoustic waves and receive reflected acoustic waves. Each of the transducers 120 may both transmit acoustic waves and receive reflected acoustic waves. In alternative embodiments, some transducers 120 may only transmit acoustic waves and some may only receive reflected waves. As used herein, the term acoustic waves includes acoustic waves in all their forms. These waves may be characterized by a frequency and a velocity. The acoustic waves may induce certain waveforms within the formation, such as compressional waves and shear waves.

In certain embodiments, the transducers 120 may generate at least one acoustic wave, including at least one of a compressional or shear wave, and receive the reflected compressional or shear wave. The time at which the acoustic wave was generated and the time at which the reflected waves are received at the transducers may be transmitted to at least one information handling system containing a processor, such as at control unit 160 in Fig. 1, which may determine an arrival time of the wave. As will be discussed below, according to aspects of the present invention, the size of the borehole 101 can then be calculated using at least the arrival time of the acoustic wave.

In certain embodiments, an information handling system may determine a path length by combining the arrival time with the speed of sound in the fluid. The path length may represent an estimation of the distance traveled by the acoustic pulse to the borehole plus the distance traveled by the reflected wave to the transducers 120. The sound velocity may vary with the composition, pressure, and temperature of the drilling fluid, though the variation may be insignificant for many applications. In many applications, the sound velocity may be assumed to be a constant value. In other applications, if temperature and pressure measurements are available, the information handling system may determine the path length using an estimated sound velocity based on known pressure and temperature coefficients.

Once the path length has been determined, the information handling system may determine a standoff distance— the distance between the transducer and the borehole wall. In the case of a single transducer, the acoustic pulse has traveled from the transducer to the borehole wall and back, causing the path length to be twice the standoff distance. If the acoustic pulse has traveled from one transducer to the borehole wall and back to another transducer, the relationship between path length and standoff distance is somewhat more complex. If an acoustic pulse has traveled from one transducer to the borehole wall and back to two or more transducers, two path lengths will be calculated and an exact (i.e., not based on an approximate expression) standoff distance can be determined.

As the drill string rotates in a LWD system, standoff distances can be measured in each direction to determine the borehole shape and the position of the caliper within the borehole. In certain embodiments, an acoustic caliper with transducers such as transducers 120 may also include an azimuthal sensor and/or a motion sensor to allow standoff distance to be measured as a function of caliper orientation and position. The azimuthal sensor may include a magnetometer to sense tool orientation relative to the local magnetic field, and/or an accelerometer to sense tool orientation relative to the local gravitational field. If present, the accelerometer may also serve as a motion sensor, allowing changes in tool position to be tracked and combined with standoff distance measurements to obtain improved borehole diameter and shape calculations. In one embodiment the caliper measurements are coupled to an azimuthally sensitive device such as a magnetometer or an inclinometer so that the shape of a borehole can be determined in relation to an azimuth or a tool-face

Figs. 2a and 2b illustrate two example paths for acoustic wave relative to an example wireline acoustic caliper 200 disposed inside a borehole 210 within a formation 220. The wireline acoustic caliper 200 may be connected with an information handling system on the surface, such as control unit 160 in Fig. 2, through wireline 230. In certain embodiments, the transducer 202 may generate the acoustic wave and transducers 204 a-d may receive reflected sonic waveform data and transmit the sonic waveform data to the surface via the wireline 230 for processing. The size of the borehole may then be determined at the surface. In other embodiments, the borehole size may be determined using at least one downhole processor, with the borehole size being transmitted to the surface.

In Fig 2a, transducer 202 may transmit a plurality of sonic waves. The sonic waves may comprise one or both of compressional waves or refracted shear waves, and may travel to the formation on a ideal path 250a, generally perpendicular to the axis of the wireline acoustic caliper 200. The time it takes the plurality of sonic waves to reach the formation typically depends on the velocity of the fluid surrounding the acoustic caliper 200. For example, in certain embodiments, the acoustic caliper 200 may be surrounded by drilling mud, the drilling mud having a particular velocity. The speed with which the plurality of sonic waves propagates within the drilling mud and therefore the time it takes the acoustic signal to reach the formation depends, at least in part, on a velocity of the drilling mud.

Once the plurality of sonic waves reaches the formation 220, the waves will propagate within the formation. Waveform data corresponding to the plurality of sonic waves will eventually be received at transducers 204 a-d over path segment 250c. The path of the acoustic waves through the formation may be represented by path segment 250b running along the borehole wall. The speed with which the plurality of sonic waves propagate within the formation 220 and the time the plurality of sonic waves take to be received by transducers 204 a- d may depend on a slowness value of the formation. Although path segment 250b is generally parallel to the acoustic caliper 200, this should not be seen as limiting, as other wave propagation paths within the formation fall within the scope of this disclosure.

Fig. 2b, in contrast illustrates a non-ideal pathway, where path segments 260a and 260c are not perpendicular to the acoustic caliper 200. In such cases, the speed and travel time of the acoustic pulses may vary from the ideal case. For example, as can be seen in Fig. 2b, path segment 260b may be shorter, meaning that the speed and travel time of the acoustic pulses are less dependent on the characteristics of formation 220.

Waveform data received at transducers 204 a-d may be processed to determine certain formation characteristics. For example, the waveform data may be processed by a data processing system to determine a velocity of wave generated by the transducer 202. The velocity of the wave may then be used to determine a slowness value of the formation. Additionally, the waveform data may be processed to identify peaks corresponding to the waves generated by the transducer 202, which can then be used to determine an arrival time of the waves. As will be discussed below, methods incorporating aspects of the present disclosure may use one or both of the velocity of the waves and the arrival time of the waves to determine the borehole size. Unlike ultrasonic data, which is limited to small boreholes less than approximately 14 3/4 inches, sonic data may valid in all hole sizes, provided that a tool can measure velocities in the environment. In general, this includes hole sizes 20 inches in diameter and larger.

In an ideal situation, such as in Fig. 2a, where the path from the transmitter to formation wall is perpendicular to the acoustic caliper tool, the Equation 1 may be used to determine the diameter of the borehole:

Equation 1 : Hole Diameter = Tool Diameter + ((Arrival Time-Formation Slowness * distance from source to receiver)/mud slowness)/2

where formation slowness is the slowness of the surrounding formation determined using at least the velocity of the generated sonic waves, according to techniques well known in the art; tool diameter is the diameter of the tool on which the transducers are disposed; the arrival time is the time is takes a generated acoustic pulse to be reflected and received at a transducer; the distance from source to receiver corresponds to the lateral distance between the source transducer to the receiver transducer; and the mud slowness corresponds to a measured or estimated speed with which sound propagates through drilling mud surrounding the measuring tool, and may be based, at least in part, on the mud velocity. The factor of two accounts for the two-way travel path through the mud.

In a non-ideal situation, a more complex version of the equation may account for the fact that the path from the source transducer to the formation wall is not perpendicular to the tool. In certain instances, the Equations 2 and 3 may be used: Equation 2: Hole Diameter = Tool Diameter + ((Arrival Time-Formation Slowness*distance from source to receiver)/(Mud Slowness*2/cos(theta)-2*Formation Slowness*tan(theta))

Equation 3: theta = real(asin(Formation Slowness/Mud Slowness)).

Fig. 3 illustrates an example measurement of a borehole using methods similar to those described above. As can be seen, Fig. 3 charts the borehole diameter versus the formation depth. The example borehole logged in Fig. 3 was drilled with a 19.5 inch diameter drill bit. Although there is significant chatter in the resulting signal due to tool eccentricity, the borehole diameter reads consistently near 20 inches except at the depth of approximately greater than 8,500 feet. At that depth, a rathole was encountered with a diameter of approximately 21.5 inches. The measurement increases to reflect the rathole.

Fig. 4 illustrates data inputs to a processing element for generating a borehole measurement similar to the one shown in Fig. 3. The left portion of Fig. 4 illustrates the example sonic waveforms transmitted from an acoustic caliper, such as acoustic caliper 200. The sonic waveform may include, in some embodiments, both a shear wave component DTS and a compressional wave component DTC. The middle section reflects the delay, or arrival time, of the wave signals. The right section reflects the velocity of the formation. Each of the data inputs may be input into an Equation such as Equations 1-3 above to determine the diameter of the borehole.

Methods in accordance with certain embodiments of the present disclosure may be effective for compressional or shear arrivals, for a tool with any number of (radial and longitudinal) transmitters and receivers, and frequencies (that the formation responds to), and any tool size. Certain embodiments of the present disclosure may be implemented with LWD (logging while drilling) or wireline. Certain embodiments of the present disclosure may be advantageous in large holes, in particular. Certain embodiments may be expanded to log while drilling and then on the trip out of the hole to check for hole degradation over time. Certain embodiments may be implemented in any mud type. Certain embodiments may have improved accuracy by jointly doing the calculation on both compressional and shear when both are available. Certain embodiments may use compressional or refracted shear to get a caliper and arrival time.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. The indefinite articles "a" or "an," as used in the claims, are defined herein to mean one or more than one of the element that it introduces.

Claims

What is claimed is:

1. A method for determining a diameter of a borehole, comprising the steps of: acquiring sonic waveform data from within the borehole, wherein the sonic waveform data is acquired at an acoustic caliper located within the borehole;

determining at a processing element communicably coupled to the acoustic caliper at least one of a velocity and an arrival time of a waveform peak; determining a mud velocity; and

calculating at the processing element the diameter of the borehole based, at least in part, on one or more of the sonic waveform data, the velocity and arrival time of the waveform peak, and the mud velocity.

2. The method of claim 1, wherein the sonic waveform data comprises at least one of a compressional wave or a refracted shear wave.

3. The method of claim 1, wherein the acoustic caliper comprises an element of a logging-while-drilling system.

4. The method of claim 1, wherein the acoustic caliper comprises a wireline logging tool.

5. The method of claim 1, wherein the processing element is included in an information handling system located at the surface.

6. The method of claim 1, wherein the step of calculating at the processing element comprises performing a calculation using the formula:

Hole Diameter = Tool Diameter + ((Arrival Time-Formation Slowness * distance from source to receiver)/mud slowness)/2.

7. The method of claim 1 , wherein the step of calculating at the processing element comprises performing a calculation using the formulae:

Hole Diameter = Tool Diameter + ((Arrival Time-Formation Slowness*distance from source to receiver)/(Mud Slowness*2/cos(theta)-2*Formation Slowness*tan(theta)); and

theta = real(asin(Formation Slowness/Mud Slowness)).

8. A method for determining a diameter of a borehole comprising the steps of:

disposing an acoustic tool at a first depth in a borehole, wherein the acoustic tool comprises a source and a receiver;

generating a plurality of waves in the borehole at the first depth, wherein the waves are generated by the source, wherein the waves comprise at least one of a compressional wave and a refracted shear wave;

determining at least one of a velocity and an arrival time of a wave received at the receiver;

determining a mud velocity; and

determining a diameter of the borehole based, at least in part, on one or more of the velocity, the arrival time, the mud velocity, a tool dimension, and a distance between the source and the receiver.

9. The method of claim 8, wherein the acoustic tool comprises an element of a logging-while-drilling system.

10. The method of claim 8, wherein the acoustic tool comprises a wireline logging tool.

11. The method of claim 8, wherein the processing element is included in an information handling system located at the surface.

12. The method of claim 8, wherein the step of calculating at the processing element comprises performing a calculation using the formula:

Hole Diameter = Tool Diameter + ((Arrival Time-Formation Slowness * distance from source to receiver)/mud slowness)/2.

13. The method of claim 8, wherein the step of calculating at the processing element comprises performing a calculation using the formulae:

Hole Diameter = Tool Diameter + ((Arrival Time-Formation Slowness* distance from source to receiver)/(Mud Slowness*2/cos(theta)-2*Formation Slowness*tan(theta)); and

theta = real(asin(Formation Slowness/Mud Slowness)).

14. The method of claim 8 further comprising:

disposing an acoustic tool at a second depth in a borehole, and

generating a plurality of waves in the borehole at the second depth.

15. An downhole apparatus for determining a diameter of a borehole, comprising: an acoustic source, wherein the acoustic source generates a plurality of waves; an acoustic receiver, wherein the acoustic receiver acquires sonic waveform data corresponding to the plurality of waves;

a processing element communicably coupled to the acoustic receiver, wherein the processing element:

receives sonic waveform data acquired by the acoustic receiver, wherein the sonic waveform data comprises at least one waveform peak,

determines at least one of a velocity and an arrival time of the waveform peak, and

determines the diameter of the borehole based, at least in part, on one or more of the velocity, the arrival time, a dimension of the downhole apparatus, and a lateral distance between the acoustic source and the acoustic receiver.

16. The apparatus of claim 15, wherein the sonic waveform data comprises at least one of compressional waves or refracted shear waves.

17. The apparatus of claim 15, wherein the downhole apparatus comprises an element of a logging-while-drilling system.

18. The apparatus of claim 15, wherein the downhole apparatus comprises an element of a logging-while-drilling system.

19. The apparatus of claim 15, wherein the processing element determines the diameter of the borehole using the formula:

Hole Diameter = Tool Diameter + ((Arrival Time-Formation Slowness * distance from source to receiver)/mud slowness)/2.

20. The apparatus of claim 15, wherein the processing element determines the diameter of the borehole using the formulae:

Hole Diameter = Tool Diameter + ((Arrival Time-Formation Slowness*distance from source to receiver)/(Mud Slowness*2/cos(theta)-2*Formation Slowness*tan(theta)); and

theta = real(asin(Formation Slowness/Mud Slowness))