WIRELESS BOTTOM HOLE POSITIONING SYSTEM

Abstract

The invention relates to wireless downhole tool (110) positioning systems (100) and methods. The method may include synchronizing a first clock with a second clock, the first clock being disposed in a first transmitter (170), the first transmitter (170) being disposed at a known location and the second clock being disposed in a downhole tool (110).The method may further include placing the downhole tool (110) in a borehole (102), the downhole tool (110) comprising a first receiver (150); transmitting a first wireless signal from the first transmitter (170) along the borehole (102) at a first time; receiving the first wireless signal via the first receiver (150) at a second time; determining a first elapsed time between the first and second times; and determining a first downhole position of the downhole tool (110) based on the first elapsed time. Fig. 1.

Description

Title of the invention: WIRELESS DOWNHOLE POSITIONING SYSTEM Technical field

[0001] The disclosure relates generally to downhole telemetry systems and methods, and in particular to downhole wireless telemetry.

[0002] CONTEXT

[0003] In downhole operations where a tool is disposed downhole, for example via a conveyance (e.g., wireline, slickline, coiled tubing, etc.) or without a conveyance (e.g., when pumped or even dropped downhole), it can be useful to have an accurate indication of a downhole location, i.e., a measured downhole depth, of the tool. With a conveyance, the lack of tension can lead to inaccurate depth readings. Without a conveyance, it can be even more difficult to know the true downhole position of the downhole tool. One solution is to use casing collar locators, but this sometimes gives a false depth if a collar is missed. Indeed, a few missed collars can lead to a significantly miscalculated depth. Brief description of the drawings

[0004] Embodiments of the disclosure may be better understood by referring to the accompanying drawings.

[0005] [Fig.l] represents a partial cross-sectional view of a downhole positioning system, according to one or more embodiments.

[0006] [Fig.2] represents a flowchart of a first method for determining a downhole position of the downhole tool, using the downhole positioning system, according to one or more embodiments.

[0007] [Fig.3] represents a graph showing the relationship between the speed of sound in water, hydrostatic pressure and temperature, according to one or more embodiments.

[0008] [Fig.4] represents a partial cross-sectional view of a second system downhole positioning system, which uses a reflected pulse to refine the downhole position of a downhole tool, according to one or more embodiments.

[0009] [Fig.5] represents a partial cross-sectional view of a third system of downhole positioning, according to one or more embodiments.

[0010] [Fig.6] depicts a partial cross-sectional view of a fourth downhole positioning system, having a second downhole tool having two or more receivers, according to one or more embodiments.

[0011] [Fig.7] shows a partial cross-sectional view of a fifth downhole positioning system, according to one or more embodiments.

[0012] [Fig.8] depicts a flowchart of a second method for determining a downhole position of the third downhole tool using the fifth downhole positioning system, according to one or more embodiments.

[0013] [Fig.9] represents a partial cross-sectional view of a sixth downhole positioning system, according to one or more embodiments.

[0014] [Fig. 10] represents a graph showing a wireless signal transmitted as a continuous signal, according to one or more embodiments.

[0015] [Fig. 11] represents an example of a computer system, according to one or more embodiments. Description of the embodiments

[0016] The following description includes examples of systems, methods, techniques, and program flows that implement embodiments of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For example, this disclosure refers to various systems, methods, and downhole tool configurations in illustrative examples. In other cases, instances of well-known instructions, protocols, structures, and techniques have not been shown in detail, so as not to obscure the description. Preview

[0017] Various systems and methods are described herein for determining a downhole position of a downhole tool, using one or more wireless signals. The wireless signal, e.g., an acoustic signal, may be transmitted from the downhole tool or the downhole tool may transmit the signal. In one or more embodiments, multiple transmitters are used, e.g., in the tool or at another location such as the surface or along the wellbore. In one or more embodiments, multiple receivers are used, e.g., in the tool or at another location such as the surface or along the wellbore. In each case, the downhole tool has a clock that is synchronized with another clock at a known location.With synchronized clocks, the timing of a received signal can be used to determine the downhole position of the downhole tool. Understanding the transmission medium, for example, whether it is a fluid or a pipe, can . be used to refine the downhole position and thus increase accuracy. For example, by determining the properties of the fluid in the well, the speed of sound can be determined and used to refine the downhole position. Examples of illustrations

[0018] [Fig.l] shows a partial cross-sectional view of a first downhole positioning system 100, according to one or more embodiments. The first downhole positioning system 100 includes a wellbore 102 that extends through, i.e., formed in, a subterranean formation 105 from a wellhead 106 located at the surface 103 (i.e., at the earth's surface). Although not shown as such, the wellhead 106 could be a subsea wellhead located where the wellbore intersects a seabed. The wellbore 102 includes casing 108 (e.g., a casing string). The casing 108 does not necessarily extend the entire length of the wellbore 102. The casing 108 may be at least partially cemented into the subterranean formation, for example via one or more cement layers 101.Although the cement 101 is shown near the surface 103, in one or more embodiments, the cement may extend the length of the wellbore 102. Although the wellbore 102 is shown as a single vertical wellbore, other implementations are possible. For example, the wellbore 102 may have one or more deviated or horizontal portions. Although a single casing 108 is shown, multiple casing strings may be arranged radially and / or circumferentially around the casing 108. Although not shown here, a casing or production string may be positioned in the wellbore 102 within the casing 108, forming an annular space between the casing string and the casing 108.

[0019] The first downhole positioning system 100 further includes a first transceiver 170. In one or more embodiments, the first transceiver 170 can both receive and transmit a wireless signal. In one or more other embodiments, the first transceiver 170 is only a transmitter (i.e., only transmits a wireless signal) or is only a receiver (i.e., only receives a wireless signal). The first transceiver 170 is communicatively coupled to a surface control unit 180. In one or more embodiments, the first transceiver 170 has a direct electrical connection to the surface control unit 180. In one or more other embodiments, the first transceiver 170 is wirelessly coupled to the surface control unit 180.In one or more embodiments, the first transceiver 170 comprises a first clock. The first transceiver 170 may be disposed at a . known location, e.g., at surface 103, at wellhead 106 (as shown), or in wellbore 102 at a known depth from surface 103.

[0020] As illustrated in [Fig.l], the first transceiver 170 may transmit a first wireless signal along the wellbore 102 to a downhole tool 110. The first wireless signal may be transmitted through a metal, through a fluid, or through both a metal and a fluid. The first wireless signal may be transmitted via the downhole tubing (e.g., casing 108, production tubing, or other downhole tubular extending along the wellbore), a fluid disposed in the wellbore 102 (e.g., the wellbore 102 may be at least partially or fully filled with a fluid), or both. In one or more embodiments, the first wireless signal is an acoustic signal transmitted via the first transceiver 170 directly through the fluid in the wellbore, e.g., via a pneumatic hammer or gun such as a nitrogen hammer.In one or more embodiments, the first wireless signal is a pressure pulse created in the fluid, a ping in the fluid or a tubular element, and optionally where the ping is a windowed signal or a windowed sinusoid.

[0021] In one or more embodiments, the downhole tool 110 includes a receiver 150. In one or more embodiments, the first wireless signal is received by or via the downhole tool 110. For example, the first wireless signal may be transmitted through the downhole tubing (e.g., casing 108 or other downhole tubular) and through a fluid disposed in the wellbore 102 for reception by the downhole tool 110. The downhole tool 110 may be disposed in the fluid. In another example, the first wireless signal may be transmitted through the fluid in the wellbore 102 and received by the downhole tool 110 through the fluid.In one or more embodiments, the downhole tool 110 is acoustically coupled to the downhole tubing (e.g., having a portion thereof touching the downhole tubing), such that the downhole tool 110 receives the first wireless signal directly via the downhole tubing.

[0022] In one or more embodiments, the downhole tool 110 includes a second clock, a machine-readable medium, and a processor. The machine-readable medium may have program code executable by the processor to perform actions or functions, including one or more methods described below. The downhole tool 110 may be a perforating gun, a plug for hydraulic fracturing, an internal tool string, a starter guide for multilateral drilling, or another downhole tool. In one or more embodiments, the downhole tool 110 operates without a transportation means. A means transport may comprise a wire rope, a smooth cable, a coiled tube or the like.

[0023] In [Fig. 1], the downhole tool 110 is shown in a first downhole position and a second downhole position, to illustrate movement of the downhole tool 110 through the wellbore 102, where the first position is closer to the wellhead 106 (and / or the first transceiver 170) than the second position. [Fig.l] further comprises a first graph 190 and a first clock symbol 195 for representing the timing of transmission of the first wireless signal at a first time 10 by the first transceiver 170, a second graph 191 and a second clock symbol 196 for representing the timing of reception of the first wireless signal at a second time ti by the receiver 150 of the downhole tool 110, and a third graph 192 and a third clock symbol 197 for representing the timing of reception of a second wireless signal at a third time 12 by the receiver 150 of the downhole tool 110. In the first graph 190, the second graph 191 and the third graph 192, the X-axis is time and the Y-axis is amplitude. In the second graph 191, a first elapsed time A / ; is the time between the first time to and the second time t ].In the third graph 192, a second elapsed time A / 2 is the time between the first time 10 and the third time 12- .

[0024] [Fig. 2] shows a flowchart of a first method 200 for determining a downhole position of the downhole tool 110, using the first downhole positioning system 100, according to one or more embodiments. In step 202, the first clock (disposed in the first transceiver 170) and the second clock (disposed in the downhole tool 110) are synchronized. For example, the first clock and the second clock may be synchronized at a surface location prior to disposing the downhole tool 110 in the wellbore 102. In another example, the first clock and the second clock may be synchronized at a downhole location, for example, when the first transceiver 170 and the downhole tool 110 are in close proximity, or via a wired electrical connection between the first transceiver 170 and the downhole tool 110.

[0025] Synchronizing the first clock and the second clock is defined as connecting at least one of the first clock or the second clock with a common clock. In one or more embodiments, the common clock is provided via a clock signal from a global positioning system (GPS). For example, the first clock may be synchronized with the GPS clock signal and then the second clock may be synchronized with the first clock, as described above. In other embodiments, the common clock may be either the first clock or the second clock. In one or more embodiments, the first clock and the second clock may be synchronized within 100 microseconds (ps) or less. This may provide a resolution of 6 inches (i.e., 152.4 mm) when the wireless signal travels through water with a speed of sound of 5,000 feet per second, or 1524 m / s (5,000 ft / sec x 0.000100 sec = 0.5 ft, or 152.4 mm). In other embodiments, the first and second clocks may be synchronized within 1,000 microseconds (ps) or less. This can provide a resolution of 60 inches (5 feet, i.e. 1524 mm) when the wireless signal travels through water with a sound speed of 5,000 feet / second, or 1524 m / s (5,000 feet / second x 0.001000 seconds = 5 feet, or 1524 mm).

[0026] In step 204, the downhole tool 110 is disposed in the wellbore 102. As described above, in one or more embodiments, the wellbore 102 contains one or more fluids, e.g., a liquid, air, or a combination thereof. The fluid may be added to the wellbore 102 from the surface, may be a produced fluid, or both. In one or more embodiments, the fluid is a known fluid, e.g., because it has been placed in the wellbore 102 and / or the chemical composition of the fluid has been determined via a sensor or measurement process. In one or more embodiments, the fluid is water or brine. In one or more embodiments, the fluid may comprise a mixture of liquid and air, e.g., a foam.The downhole tool 110 may be disposed in the fluid, and lowered to a first downhole position, i.e., a first location in the wellbore. (Prior to completion of the first method 200, this first downhole position may not be known with much certainty.) In one or more embodiments, the downhole tool 110 is pumped into and / or with the fluid and along the wellbore 102 to the first downhole position. For example, one or more pumps may be used at the surface 103 or at the wellhead 106 to force the downhole tool 110 downward into and along the wellbore via pumping of the fluid. In one or more embodiments, the downhole tool 110 is not attached to the surface by any transport means (e.g., tubular member, wireline, slickline, coiled tubing, or the like).

[0027] At step 206, a first wireless signal is transmitted from the first transceiver 170 along the wellbore 102 at the first time 10, as illustrated in the first graph 190 of [Fig.l] and the first clock symbol 195. As discussed above, the first wireless signal may be transmitted through the fluid, through a downhole tube disposed in the wellbore (e.g., the casing 108, the production tubing or other type of downhole tubular member), or both.

[0028] In step 208, the first wireless signal is received via the downhole tool 110 at the second time 1;, as illustrated in the second graph 191 of [Fig.l] and the second clock symbol 196. The downhole tool 110 may receive the first wireless signal via the receiver 150. The reception time of the first wireless signal, i.e., the second time 11, may be recorded by the downhole tool 110.

[0029] In step 210, the first elapsed time A / ; between the first time 10 and the second time tj is determined. In one or more embodiments, the machine-readable medium in the downhole tool 110 may have program code executable by the processor to determine the first elapsed time A / ; based on the first time 10 and the second time 1. Since the first clock and the second clock are synchronized, the difference between the second time ty and the first time 10 may be determined. In one or more embodiments, the transmission of the first wireless signal only occurs at a set time. For example, the transmission from the surface may occur every minute, every 30 seconds, every second or every millisecond, or at any other regular interval.In this example, the downhole tool 110 may determine the first elapsed time A / ; by subtracting the second time tj from the set time, i.e., assigning the set time as the first time 10. The regular interval from the set time may be determined based on the maximum expected transmission time based on the length of the wellbore 102, the transmission medium, the wellbore temperature profile, and / or the wellbore pressure profile.

[0030] In step 212, the first downhole position of the downhole tool 110 is determined based on the first elapsed time A / j. The relationship between the first downhole position, i.e., the measured depth of the tool along the wellbore, and the elapsed time A / j is determined based on the speed of sound in the transmission medium (e.g., the fluid, the downhole tubing, or both through which the wireless signal passes) and the attenuation. If the transmission medium is the downhole tubing, e.g., steel, the speed of the first wireless signal is nearly constant, but the transmission distance may be limited due to signal attenuation. Systems that rely entirely on acoustic transmission through the tubular member will often employ repeaters due to attenuation.Thus, when one or more repeaters are used between the first transceiver 170 and the receiver 150, the delay of the repeater can also be taken into account in determining the first downhole position on the base. of elapsed time A / Alternatively, the downhole tool 110 may calculate its position relative to at least one of the one or more repeaters.

[0031] If the transmission medium is the fluid, then the speed of sound will vary with the temperature and hydrostatic pressure of the fluid. By knowing the fluid, either because it was deliberately introduced into the wellbore 102 or by determining the composition of the fluid, the speed of sound can be estimated based on the temperature and pressure of the fluid in the wellbore 102.

[0032] [Fig. 3] depicts a graph 300 showing the relationship between the speed of sound in water, hydrostatic pressure, and temperature, according to one or more embodiments. The Y-axis of graph 300 represents the speed of sound in feet / second, the X-axis represents the hydrostatic pressure in pounds per square inch (psi), keeping in mind that 1 psi is 6894.76 Pa. Three curves are shown for three different temperatures in degrees Fahrenheit (F), 50°F, 150°F, and 250°F (or 10°C, 65.6°C, and 121.1°C, respectively). As shown, the speed of sound increases with pressure when the temperature is held constant. Graph 300 also illustrates the importance of knowing the temperature, since the speed of sound can vary with temperature in a non-linear manner.

[0033] The downhole tool 110 may include a pressure sensor, a temperature sensor, or both, for example, the pressure sensor and / or the temperature sensor may be disposed in the downhole tool 110. In one or more embodiments, the pressure sensor may measure a pressure in the wellbore 102 with the pressure sensor to provide a measured pressure. In one or more embodiments, the temperature sensor may measure a temperature in the wellbore 102 with the temperature sensor to provide a measured temperature. The estimated speed of sound may be based on at least one of the measured pressure or the measured temperature. In one or more embodiments, only the pressure is measured or only the temperature is measured.For example, the temperature can be assumed based on the fluid and previous measurements (e.g., measurements from external sources or measurements from nearby wells) and the pressure can be measured by the pressure sensor in the tool. In another example, the pressure can be assumed based on the fluid and previous measurements and the temperature can be measured by the temperature sensor.

[0034] In one or more embodiments, the pressure in the wellbore 102 may be determined based on a pressure profile along the wellbore (e.g., previously measured or assumed based on external data) to provide a determined pressure. In one or more embodiments, the temperature in the wellbore 102 may be determined based on a profile temperature along the wellbore (e.g., previously measured or assumed based on external data) to provide a determined temperature. The estimated sound may be based on at least one of the determined pressure or the determined temperature. In one or more embodiments, the pressure profile is assumed to be linear along the wellbore that accounts for hydrostatic pressure and frictional pressure drops. In one or more embodiments, the temperature profile is assumed to be linear along the wellbore. In one or more embodiments, the temperature along the wellbore, the pressure along the wellbore, or both may be determined via one or more numerical models.During pumping of the downhole tool 110, the temperature variation along the wellbore 102 can be minimized, because the fluid pumped into the wellbore 102 can cool the wellbore 102.

[0035] The first method 200 may be repeated as the downhole tool 110 moves along the wellbore 102. In [Fig.l], the downhole tool 110 is also shown in the second downhole position, i.e., showing the downhole tool 110 further along the wellbore 102, i.e., at a greater measured depth. With the downhole tool 110 moved to a new position (i.e., the second downhole position), a second wireless signal may be transmitted from the first transceiver 170 along the wellbore 102 at the first time 10, although this "first time" is a new "first time," i.e., it is a different time than the time used to transmit the signal when the tool was at the first downhole position.However, this "first time" may be a time defined according to the programming of both the downhole tool 110 and the first transceiver 170, and for illustrative purposes is treated as the first time 10 to show the difference in time elapsed between reception when the downhole tool 110 is at the first downhole position and when the downhole tool 110 is at the second downhole position.

[0036] The second wireless signal is received via the downhole tool 110 (i.e., via the receiver 150) at the third time 12. As mentioned above, the third graph 192 and the third clock symbol 197 illustrate the timing of the reception of the second wireless signal at the third time 12 by the receiver 150 from the downhole tool 110, where the reception at the third time 12 by the receiver 150 is due to the downhole tool being located at the second downhole position.

[0037] The second elapsed time A / 2 is then determined. As illustrated in the third graph 192, the second elapsed time A / 2 is the time between the first time to and the third time 12. In one or more embodiments, the support machine-readable in the downhole tool 110 may have program code executable by the processor to determine the second elapsed time A / 2 based on the first time t0 and the third time 12. Since the first clock and the second clock are synchronized, the difference between the third time 12 and the first time 10 may be determined. In one or more embodiments, the transmission of the second wireless signal occurs only at a set time or time interval, such as at the same interval as the first wireless signal. For example, transmission from the surface may occur every minute, every 30 seconds, every second, or every millisecond, or at any other regular interval.In this example, the downhole tool 110 may determine the second elapsed time A / 2 by subtracting the third time 12 from the set time, i.e., assigning the set time as the first time 10. As illustrated, the second elapsed time A / 2 is longer than the first elapsed time A / j due to the downhole tool 110 moving to the second downhole position, i.e., having moved further from the first transceiver 170. Based on the second elapsed time A / 2, the second downhole position is determined, for example, by taking into account the speed of sound in the transmission medium, attenuation, etc. as described above.

[0038] [Fig. 4] depicts a partial cross-sectional view of a second downhole position system 400 that uses a reflected pulse to refine the downhole position of a second downhole tool 410, according to one or more embodiments. In the second downhole position system 400, the downhole tool 410 has the capability to receive a reflected or secondary signal via a receiver 450. As with the first downhole position system 100, the first transceiver 170 transmits the first wireless signal at a first time to and receives the first wireless signal via the receiver 450 at a second time. Similarly, the first elapsed time A / ; may be determined based on the difference between the first time 10 and the second time 1 and the first downhole position may be determined based on the first elapsed time A / ;.

[0039] In addition to receiving the first wireless signal at the first time 1i, the receiver 450 receives the secondary signal at the third time t „ as represented by a graph 493. The secondary signal may be a reflection of the first wireless signal off the wellbore bottom 411 (as illustrated), off a downhole tubular (e.g., a lower completion), or off another downhole object (e.g., a packer, sleeve, shoe, other downhole tool, or the like). For example, when the first wireless signal is transmitted in a fluid, e.g., water or brine, the first wireless signal may often be reflected on the downhole 411. A second elapsed time A / R may be determined based on the difference between the first time 10 and the third time t r. As long as the downhole position, i.e., the measured depth, of the object providing the source of the secondary signal is known, e.g., the downhole 411 may be at a known measured depth, the first downhole position may be refined or updated based on the second elapsed time A / R.

[0040] [Fig. 5] shows a partial cross-sectional view of a third downhole positioning system 500, according to one or more embodiments. The third downhole position system 500 includes one or more transceivers for transmitting one or more wireless signals. As illustrated, the third downhole position system 500 includes two such transceivers, the first transceiver 170 and a second transceiver 572. The second transceiver 572 is disposed at a known location. For example, the second transceiver 572 may be disposed at the surface, at the wellhead 106 or along the wellbore 102 (e.g., coupled to the casing 108 as illustrated or to a casing string disposed within the casing 108), at a known distance from the surface, i.e., a known depth.In one or more embodiments, the second transceiver 572 is located along the wellbore 102 at a fixed distance from the first transceiver 170. In one or more embodiments, the second transceiver 572 can both receive and transmit a wireless signal. In one or more other embodiments, the second transceiver 572 is only a transmitter (i.e., only transmits a wireless signal) or is only a receiver (i.e., only receives a wireless signal).

[0041] With the downhole tool 110 still at the first position, the second transceiver 572 may act as a second transmitter and may transmit a second wireless signal along the wellbore 102. In one or more embodiments, the second transceiver 572 transmits the second wireless signal along the wellbore 102 at the first time 10, and the receiver 150 in the downhole tool 110 may receive the second wireless signal at a fourth time 13, as shown in graph 594. For example, both the first transceiver 170 and the second transceiver 572 may transmit their respective signals at the same time, but the second wireless signal may have a different frequency than the first wireless signal.The downhole tool 110, for example, via program instructions executed by the processor, may determine a third elapsed time A / 3 based on a difference between the first time 10 and the fourth . time 13. Based on the third elapsed time A / 3, the downhole tool 110, for example via the processor, can refine the first downhole position.

[0042] In one or more embodiments, the second transceiver 572 transmits the second wireless signal along the wellbore 102 at a fifth time 14 as illustrated by graph 590 (i.e., transmitting at a different time than transmitting the first wireless signal from the first transceiver 170), and the receiver 150 in the downhole tool 110 may receive the second wireless signal at a sixth time 15 as illustrated by graph 595. The downhole tool 110, for example, via program instructions executed by the processor, may determine a fourth elapsed time A / 4 based on a difference between the sixth time 15 and the fifth time 14. Based on the fourth elapsed time A / 4, the downhole tool 110, for example, via the processor, may refine the first downhole position.

[0043] In one or more embodiments, additional transceivers may be added along the wellbore or at the surface, each of which may operate in one of the ways described above, to provide different elapsed times that may be used to refine the first downhole position. For example, one or more additional transceivers (such as one or more repeaters for an acoustic telemetry system) disposed a known distance from the surface may be used to transmit a signal to the downhole tool. The elapsed time between transmission and reception of the signal by the downhole tool 110 may be used to further refine the first downhole position of the downhole tool 110 or to further refine the speed of sound of the wireless signal.

[0044] [Fig. 6] depicts a partial cross-sectional view of a fourth downhole positioning system 600 having a third downhole tool 610 having two or more receivers, according to one or more embodiments. As illustrated, the third downhole tool 610 has at least a first receiver 650 and a second receiver 652. In one or more embodiments, the first receiver 650 is disposed in an upper portion of the third downhole tool 610 (e.g., a portion of the third downhole tool 610 that is closer to the wellhead 106) and the second receiver 652 is disposed in a lower portion of the third downhole tool 610, i.e., the second receiver 652 is disposed farther from a transmitter (e.g., the first transceiver 170) than the first receiver 650.

[0045] During operation of the third downhole tool 610, a first wireless signal is transmitted from the first transceiver 170 along the wellbore. drilling 102 at the first time 10 (as described in step 206). Similar to that described in step 208 above, the first wireless signal is received at a second time 1; via the first receiver 650. The first wireless signal is also received at the seventh time 16 via the second receiver 652 as illustrated by graph 696. In one or more embodiments, a sixth elapsed time A / 6 may be determined based on a difference between the seventh time 16 and the first time 10. A time delay between the second time 17 and the seventh time 16 may be determined, the speed of sound may be estimated and / or refined based on the time delay, and the first downhole position may be refined. In one or more embodiments, the first elapsed time A / j and the sixth elapsed time A / 6 may be compared and / or used to estimate or refine the sound velocity and then refine the first downhole position.

[0046] [Fig. 7] depicts a partial cross-sectional view of a fifth downhole positioning system 700, according to one or more embodiments. The fifth downhole positioning system 700 includes the wellbore 102 extending through the subterranean formation 105 from the wellhead 106 and including the casing 108. As with the other described embodiments, although a single casing 108 is shown, multiple casing strings may be disposed radially and / or circumferentially around the casing 108. Additionally, although not shown, a casing or production string may be placed in the wellbore 102 within the casing 108, forming an annular space between the casing string and the casing 108.

[0047] The fifth downhole positioning system 700 includes a third receiver 770. The third receiver 770 is communicatively coupled to a surface control unit 180, for example, via a direct electrical connection, a fiber optic connection, or a wireless connection. In one or more embodiments, the third receiver 770 includes a first clock. The third receiver 770 may be disposed at a known location, for example, at the surface 103, at the wellhead 106 (as shown), or in the wellbore 102 at a known depth from the surface 103, for example, coupled to the casing 108 or other downhole tubular member.

[0048] In one or more embodiments, the fourth downhole tool 710 includes a first transmitter 760. The first transmitter 760 may transmit a first wireless signal along the wellbore 102 to the third receiver 770. The first wireless signal may be an acoustic signal or a pressure signal. The first wireless signal may be transmitted via the downhole tubing (e.g., casing 108, production tubing, or other downhole tubular member extending along the wellbore), a fluid disposed in the wellbore 102, or both. In one or more embodiments, the first wireless signal is an acoustic signal transmitted via the first transmitter 760 directly through the fluid in the wellbore, for example, via a pneumatic hammer or gun such as a nitrogen hammer. In one or more embodiments, the first wireless signal is a pressure pulse created in the fluid, a ping in the fluid or a tubular member, and optionally where the ping is a windowed signal or a windowed sinusoid.

[0049] In one or more embodiments, the first wireless signal is received by or via the third receiver 770. For example, the first wireless signal may be transmitted through the downhole tubing (e.g., casing 108 or other downhole tubular) and / or through a fluid disposed in the wellbore 102 to be received by the third receiver 770. The fourth downhole tool 710 may be disposed in the fluid. In another example, the first wireless signal may be transmitted through the fluid in the wellbore 102 and received by the third receiver 770 through the fluid.In one or more embodiments, the fourth downhole tool 710 is acoustically coupled to the downhole tubing (e.g., having a portion thereof touching the downhole tubing) such that the fourth downhole tool 710 transmits the first wireless signal directly via the downhole tubing to the third receiver 770.

[0050] In one or more embodiments, the fourth downhole tool 710 includes a second clock. The surface control unit 180 may include a machine-readable medium and a processor. The machine-readable medium may have program code executable by the processor to perform actions or functions, including one or more methods described below.

[0051] The fourth downhole tool 710 is shown at a first downhole position. [Fig. 7] further includes a first graph 790 for describing the timing of transmission of the first wireless signal at a first time 10 by the first transmitter 760 and a second graph 791 for describing the timing of reception of the first wireless signal at a second time 1; by the third receiver 770. In the second graph 791, a first elapsed time A / j is the time between the first time 10 and the second time t ]. A first downhole position of the fourth downhole tool 710 may be determined based on the first elapsed time A / ;.

[0052] [Fig.8] shows a flowchart of a second method 800 for determining a downhole position of the fourth downhole tool 710 using the fifth downhole positioning system 700, according to one or more embodiments. In step 802, the first clock (disposed in the third receiver 770) and the second clock (disposed in the fourth downhole tool 710) are synchronized. For example, the first clock and the second clock may be synchronized at a surface location, prior to disposing the fourth downhole tool 710 in the wellbore 102. In another example, the first clock and the second clock may be synchronized at a downhole location, for example, when the third receiver 770 and the fourth downhole tool 710 are in close proximity or via a hardwired electrical connection between the third receiver 770 and the fourth downhole tool 710. The synchronization of the first clock and the second clock may be as described above in connection with Figures 1-2.

[0053] In step 804, the fourth downhole tool 710 is disposed in the wellbore 102. As described above, in one or more embodiments, the wellbore 102 contains one or more fluids, e.g., a liquid, air, or a combination thereof. The fluid may be added to the wellbore 102 from the surface, may be a produced fluid, or both. In one or more embodiments, the fluid is a known fluid, e.g., because it has been placed in the wellbore 102 and / or the chemical composition of the fluid has been determined via a sensor or measurement process. In one or more embodiments, the fluid is water or brine. In one or more embodiments, the fluid may comprise a mixture of liquid and air, e.g., a foam.The fourth downhole tool 710 may be disposed in the fluid, and lowered to a first downhole position, i.e., a first location in the wellbore. (Prior to completion of the second method 800, this first downhole position may not be known with much certainty.) In one or more embodiments, the fourth downhole tool 710 is pumped into and / or with the fluid and along the wellbore 102 to the first downhole position. For example, one or more pumps may be used at the surface 103 or at the wellhead 106 to force the fourth downhole tool 710 downward into and along the wellbore via pumping of the fluid.In one or more embodiments, the fourth downhole tool 710 is not attached to the surface by any transport means (e.g., tubular, wireline, slickline, coiled tubing, or the like).

[0054] At step 806, a first wireless signal is transmitted from the first transmitter 760 along the wellbore 102 at the first time 10, as illustrated in the first graph 790 of [Fig. 7]. As discussed above, the first wireless signal may be transmitted through the fluid, through a downhole tube disposed in the wellbore (e.g., casing 108, production tubing, or other type downhole tubular element), or both. In step 808, the first wireless signal is received via the third receiver 770 at the second time 1;, as illustrated in the second graph 791 of [Fig.7]. The reception time of the first wireless signal, i.e., the second time 1i, may be recorded by the third receiver 770 and / or the connected surface control unit 180.

[0055] In step 810, the first elapsed time A / ; between the first time 10 and the second time tj is determined. In one or more embodiments, the machine-readable medium in the surface controller 180 may have program code executable by the processor to determine the first elapsed time A / , based on the first time 10 and the second time t ]. Since the first clock and the second clock are synchronized, the difference between the second time 1; and the first time 10 may be determined. In one or more embodiments, the transmission of the first wireless signal only occurs at a set time. For example, the transmission from the surface may occur every minute, every 30 seconds, every second or every millisecond, or at any other regular interval.In this example, the surface control unit 180 may determine the first elapsed time A / j by subtracting the second time 1; from the set time, i.e., assigning the set time as the first time 1;. The regular interval from the set time may be determined based on the maximum expected transmission time based on the length of the wellbore 102, the transmission medium, the temperature profile of the wellbore, and / or the pressure profile of the wellbore.

[0056] In step 812, the first downhole position of the fourth downhole tool 710 is determined based on the first elapsed time A / ;. As described above, the relationship between the first downhole position, i.e., the measured depth of the tool along the wellbore, and the elapsed time A / j is determined based on the speed of sound in the transmission medium (e.g., the fluid, the downhole casing, or both through which the wireless signal passes) and the attenuation. If the transmission medium is the downhole tubing, e.g., steel, the speed of the first wireless signal is nearly constant, but the transmission distance may be limited due to signal attenuation. Systems that rely entirely on acoustic transmission through the tubular member will often employ repeaters due to attenuation.Thus, when one or more repeaters are used between the third receiver 770 and the first transmitter 760, the delay of the repeater can also be taken into account in determining the first downhole position based on the elapsed time A / h If the transmission medium is fluid, then the speed of sound will vary with temperature and . fluid pressure. Knowing the fluid, the speed of sound can be estimated based on the wellbore temperature and pressure, as described above.

[0057] The second method 800 may be repeated as the fourth downhole tool 710 moves along the wellbore 102. For example, as the fourth downhole tool 710 moves to a second downhole position, the first transmitter 760 may transmit a second wireless signal through the wellbore 102 to the third receiver 770. Based on the timing of the reception of the second wireless signal, the time elapsed between the transmission of the second wireless signal and its reception may be determined and then used to determine the second downhole position. The pressure and / or temperature determinations, as described above, may also be used to determine the speed of sound and refine the first downhole position or the second downhole position.

[0058] Figures 2 and 8 are annotated with a series of numbers. These numbers may represent steps of operations. Although these steps are ordered for this example, the steps illustrate an example to aid in understanding this disclosure and should not be used to limit the claims. The subject matter within the scope of the claims may vary depending on the order and some of the operations. For example, other operations may be performed prior to the determination of elapsed time or downhole positions, e.g., a determination of sound speed and / or determining whether one or more repeaters are used. The flowcharts are provided to aid in understanding the illustrations and should not be used to limit the scope of the claims. The flowcharts describe examples of operations that may vary within the scope of the claims.Additional operations can be performed; fewer operations can be performed; operations can be performed in parallel; and operations can be performed in a different order.

[0059] [Fig. 9] shows a partial cross-sectional view of a sixth downhole positioning system 900, according to one or more embodiments. The sixth downhole positioning system 900 is similar to the fifth downhole positioning system 700 shown in [Fig. 7], but further includes a casing string 904 (sometimes referred to as a production string or tubing) disposed within the casing 108. The casing string 904 is arranged such that the casing 108 is circumferentially disposed around the casing string 904 forming an annular space 909 therebetween. The sixth downhole positioning system 900 further includes one or more repeaters (two are shown: a first repeater 972 and a second repeater 974) each at known depths (i.e., at known measured depths along the axis of the wellbore 102).The one or more repeaters can be . one or more transceivers. In one or more embodiments, the second transceiver 572 is a repeater. The first repeater 972 and the second repeater 974 may both be coupled to an exterior surface of the casing string 904, i.e., in the annulus 909. Alternatively, at least one of the first repeater 972 and the second repeater 974 may be included in a separate double female coupler or downhole mandrel (not shown) that is coupled (e.g., via one or more threads or one or more fasteners) to the casing string 904.

[0060] The one or more repeaters may operate to receive and retransmit a wireless signal when a signal loss occurs (e.g., due to attenuation, interference, distortion, or the like). As described above, one or more repeaters may be used where the wireless signal is transmitted entirely or primarily via the tubing (e.g., via the casing string 904). For example, when the first transmitter 760 produces a wireless signal (e.g., the first wireless signal), the one or more repeaters may receive the wireless signal and optionally retransmit the received wireless signal. The timing of the signals received by the one or more repeaters may be used in the sixth downhole positioning system 900 to further refine the downhole position of the fourth downhole tool 710.

[0061] For example, the fourth downhole tool 710 is to be disposed at the first downhole position. As described in the second method 800, the first wireless signal is transmitted from the first transmitter 760 along the wellbore 102 at the first time 10, as illustrated in the first graph 790, and the first wireless signal is received via the third receiver 770 at the second time 11, as illustrated in the second graph 791. In addition to the first wireless signal being received by the third receiver 770, the first wireless signal may also be received by the one or more repeaters. For example, the first repeater 972 may receive the first wireless signal at an eighth time 17, as illustrated in the third graph 992, and the second repeater 974 may receive the first wireless signal at a ninth time 18, as illustrated in the fourth graph 993.The timing of the reception of the first wireless signal by the third receiver 770, the first repeater 972 and the second repeater 974 depends on the distance of each of them from the fourth downhole tool 710. For example, the first repeater 972 is shown as being closer to the fourth downhole tool 710 than the third receiver 770 or the second repeater 974, and thus the eighth time 17 is shown as being less than the second time 17 or the ninth time t s- .

[0062] As with the third receiver 770, for each of the one or more repeaters, an elapsed time may be determined from the time of transmission of the first wireless signal and its reception by the respective receiver. In one or more embodiments, a seventh elapsed time A / 7 between the first time to and the eighth time / 7 and an eighth elapsed time A / s between the first time 10 and the ninth time 18 are determined. For example, the first repeater 972 and the second repeater 974 may be communicatively coupled to the surface control unit 180 (e.g., via a wired or wireless connection), the first repeater 972 and the second repeater 974 may communicate the reception time to the surface control unit 180, and the machine-readable medium in the surface control unit 180 may have program code executable by the processor to determine the seventh elapsed time At 7 and the eighth elapsed time A / s.In one or more embodiments, each of the first repeater 972 and the second repeater 974 may have logic, circuitry, a processor, or the like to determine the elapsed time and then communicate the elapsed time to the surface, for example, to the surface controller 180. Based on the seventh elapsed time A / 7, the eighth elapsed time A / s, or both, and based on the known depths of the first repeater 972 and the second repeater 974, the first downhole position may be refined and / or updated.

[0063] Although the first repeater 972 and the second repeater 974 are described as operating as receivers receiving the first wireless signal from the first transmitter 760, it should be understood that the first repeater 972 and the second repeater 974 may conversely operate as transmitters and be used with the downhole tool 110 as described in [Fig. 5] with respect to the third downhole position system 500. For example, the receiver 150 may receive a signal transmitted from at least one of the first repeater 972 or the second repeater 974 (each at known depths) and determine or refine the downhole position of the downhole tool 110.

[0064] [Fig. 10] depicts a fifth graph 1000 showing a transmitted signal 1030 as a continuous signal, according to one or more embodiments. In one or more embodiments, the wireless signal transmitted by the first transceiver 170, the second transceiver 572, the first transmitter 760, or one of the repeaters is a continuous signal, e.g., a continuous waveform. For example, as depicted, the transmitted signal 1030, e.g., the first wireless signal, is represented as a continuous sine wave. In one or more embodiments, the continuous signal is transmitted using a siren, e.g., in a fluid disposed in the wellbore 102. In one or more embodiments, a continuous resonance or "hiss" may be created as a continuous acoustic signal (e.g., in the tube, in the fluid, or both).

[0065] When a continuous signal is transmitted, the received signal will appear as a time-shifted continuous signal to the receiver (e.g., receiver 150, first receiver 650, second receiver 652, or third receiver 770). For example, a received signal 1032 may appear as a time-shifted signal relative to the transmitted signal 1030. This time shift, Δt, between the transmitted signal 1030 and the received signal 1032, for example, measured peak-to-peak as illustrated, may be used just like the elapsed time above to determine the downhole position of the downhole tool (e.g., downhole tool 110, third downhole tool 610, or fourth downhole tool 710). In one or more embodiments, the phase shift between the transmitted signal 1030 and the received signal 1032 is used to determine the downhole position of the downhole tool.

[0066] In one or more embodiments, the positional accuracy, e.g., the determined downhole position, may be refined by passing known locations within the wellbore 102. For example, as the downhole tool (e.g., any of the downhole tools listed above) passes one or more known locations, e.g., one or more magnetic tags, one or more casing collars, etc., the sound velocity estimate may be corrected and / or the previously determined downhole position may be updated or refined.In one or more embodiments, the known location is a laydown location of the downhole tool, e.g., if the downhole tool is a service string, and a change in timing between the laydown location and the reverse location may be determined, e.g., one or more methods described above, to verify whether the downhole tool is at the proper location, e.g., in a multi-zone completion operation. For example, the exact location of the reverse location and the downhole position of the tool between the reverse location and the laydown location may be accurately determined using one or more of the methods and systems described above.

[0067] When determining a particular downhole position, e.g., the first downhole position or the second downhole position, the downhole tool (e.g., any of the downhole tools listed above) may automatically perform one or more actions, e.g., take a measurement, set a tool or valve or plug, setting itself (e.g., a self-setting frac plug), or the like. For example, the downhole tool may be a frac plug with a setting tool that may set itself when it reaches a target location, the target location being the first downhole position or the second downhole position. This may allow setting of the plug without connection to a conveyance, for example, without connection to a wireline or slickline. In another example, the downhole tool may be a perforating gun, not attached to a conveyance, which may fire when it reaches a target location, the target location being the first downhole position or the second downhole position. In yet another example, the downhole tool may be a sensor which may take one or more measurements or readings and record the downhole position at each measurement or reading and / or take one or more measurements or readings at a specific downhole position or within a window of specific positions.In yet another example, the downhole tool may be a service string in the wellbore 102 that can know when it has reached the laydown location, e.g., a first downhole position, and when it has reached a recirculation position, e.g., a second downhole position. The service string may be disposed in the wellbore 102 via a conveyance means, e.g., a wireline, a slickline, a coiled wire, a coiled tubing, etc.

[0068] The above wireless signals (e.g., the first wireless signal or the second wireless signal) may be one or more acoustic signals or pressure signals. For example, the wireless signal may have a frequency ranging from about 1 megahertz (MHz) to about 1 kilohertz (kHz) to about 0.1 hertz (Hz). A wireless signal of about 0.1 Hz may be considered a pressure pulse or a pressure signal.

[0069] In one or more embodiments, the wireless signal is an acoustic signal created with mud pulse technology. For example, a positive pulse generator, a negative pulse generator, or a siren may be used at the surface of the wellbore 102, such as at the wellhead 106, to transmit the acoustic signal. In one or more embodiments, the wireless signal is an acoustic signal created by a hydrophone transmitter, for example, the first transceiver 170, the second transceiver 572, or the first transmitter 760, may be a hydrophone transmitter using electromagnetic or piezoelectric signals to create the acoustic signal. In one or more embodiments, the wireless signal is an acoustic signal created by a valve that releases compressed gas into the fluid in the wellbore 102.

[0070] It will be understood that each block of the flowcharts (e.g., in Figures 2 and 8) and other processes disclosed herein may be implemented by program code. The program code may be provided to a processor of a computer general purpose computer, special purpose computer, or other programmable machine or device. As will be appreciated, aspects of the disclosure may be implemented as a system, method, or program code (or instructions) stored on one or more machine-readable media. Accordingly, the aspects may take the form of hardware, software (including firmware, resident software, microcode, etc.), or a combination of software and hardware aspects that may generally be referred to herein as a “circuit,” a “module,” or a “system.” Functionality shown as individual modules / units in the illustrative examples may be organized differently depending on any of the platform (operating system and / or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.

[0071] Any combination of one or more machine-readable media may be used. The machine-readable medium may be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium may be, for example, but not limited to, a system, apparatus, or device that uses one or more electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technologies to store program code. More specific examples (but not limited to) of the machine-readable storage medium would include: a portable computer floppy disk, a hard disk drive, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing.A machine-readable storage medium may be any tangible medium that can contain or store a program for use by or in connection with an instruction-executing system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal carrier. A machine-readable signal carrier may comprise a propagated data signal with machine-readable program code embedded therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electromagnetic, optical, or any suitable combination thereof.A machine-readable signal medium may be any machine-readable medium that is not a machine-readable storage medium and that can communicate, propagate, or carry a program for use by or in connection with an instruction-executing system, apparatus, or device.

[0072] The program code embodied on a machine-readable medium may be transmitted using any suitable medium, including, but not limited to, wireless, wired cable, fiber optic cable, radio frequency (RF), etc., or any suitable combination of the foregoing. The computer program code for performing operations for aspects of the disclosure may be written in any combination of one or more programming languages, including an object-oriented programming language such as the Java® programming language, C++, or the like; a dynamic programming language such as Python; a scripting language such as the Perl programming language or the PowerShell scripting language; and procedural programming languages, such as the "C" programming language or similar programming languages.The program code may execute entirely on a stand-alone machine, may execute in a distributed manner across multiple machines, and may execute on one machine while providing results and / or accepting inputs on another machine. The program code / instructions may also be stored in a machine-readable medium that may direct a machine to operate in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture having instructions that implement the function / act specified in a flowchart and / or block diagram block or blocks.

[0073] [Fig. 11] shows an exemplary computer system 1100, according to one or more embodiments. The computer system 1100 may be included in or be a component of the surface control unit 180, the downhole tool 110, the second downhole tool 410, the third downhole tool 610 and / or the third receiver 770. The computer system 1100 includes a processor 1101 (possibly including multiple processors, multiple cores, multiple nodes and / or implementing multithreading, etc.). As noted above, the processor may be included in or be a component of the surface control unit 180, the downhole tool 110, the second downhole tool 410, the third downhole tool 610, and / or the third receiver 770, for example, by executing one or more machine-readable instructions stored as program code.The computer system 1100 also includes a memory 1107. The memory 1107 may be a system memory or one or more of the possible embodiments already described above of machine-readable media. In addition, the computer system 1100 includes a bus 1103 and a network interface 1105. The computer system 1100 communicates via transmissions to and / or from remote devices via the network interface 1105 according to a network protocol corresponding to the type of network interface, wired or wireless and according to the transport medium. Additionally, communication or transmission may involve other layers of a communication protocol and / or suites of communication protocols (e.g., Transmission Control Protocol, Internet Protocol, User Datagram Protocol, Virtual Private Network protocols, etc.). The system also includes a clock 1111. The clock 1111 may be at least one of the first clock and the second clock described above. Any of the functionality described above may be partially (or entirely) implemented in hardware and / or on the processor 1101. For example, the functionality may be implemented with an application-specific integrated circuit, in logic implemented in the processor 1101, in a coprocessor on a peripheral device or card, etc. In addition, the embodiments may include fewer or additional components not shown in [Fig.11] (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). Processor 1101 and network interface 1105 are coupled to bus 1103. Although illustrated as coupled to bus 1103, memory 1107 may be coupled to processor 1101.

[0074] Although aspects of the disclosure are described with reference to various implementations and operations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited thereto. In general, the techniques for synchronizing clocks and determining elapsed time, as described herein, may be implemented with facilities compatible with any hardware system or systems. Many variations, modifications, additions, and improvements are possible. Multiple instances may be provided for the components, operations, or structures described herein as a single instance. Finally, the boundaries between the various components, operations, and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations.Other assignments of functionality are contemplated and may be within the scope of the disclosure. In general, structures and functionality shown as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality shown as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may be within the scope of the disclosure. Terminology

[0075] Unless otherwise indicated, the use of the terms “connect,” “engage,” “couple,” “attach,” or any other similar term describing an interaction between elements is not intended to limit the interaction to a direct interaction between the elements, and may also include indirect interaction between the elements described. For example, antennas may be inductively coupled without touching. Unless otherwise indicated, the use of the terms "up," "upper," "up," "top of hole," "upstream," or other similar terms shall be interpreted as extending generally from the formation toward the surface, for example, toward wellhead 106 in [Fig. 1], or toward the surface of a body of water; similarly, the use of "down," "lower," "down," "bottom of hole," "downstream," or other similar terms shall be interpreted as generally in the formation away from the surface or away from the surface of a body of water, regardless of the orientation of the wellbore. The use of one or more of the foregoing terms shall not be interpreted as referring to positions along a perfectly vertical axis.Unless otherwise specified, the use of the term "subterranean formation" shall be construed to include both areas below the exposed earth's surface and areas below the earth's surface covered by water, such as oceans or freshwater bodies.

[0076] The use of the phrase "at least one of" preceding a list with the conjunction "and" should not be treated as an exclusive list and should not be construed as a list of categories with one element from each category, unless otherwise stated. A clause that states "at least one of A, B, and C" may only be violated with one of the listed elements, more than one of the listed elements, and one or more elements from the list and one other element not listed. Example Embodiments

[0077] Numerous examples are provided herein to enhance understanding of the present disclosure. A specific set of exemplary embodiments is provided as follows:

[0078] Example A: A method, comprising: synchronizing a first clock with a second clock, the first clock being disposed in a first transmitter, wherein the first transmitter is disposed at a known location, and wherein the second clock is disposed in a downhole tool; disposing the downhole tool in a wellbore, the downhole tool comprising a first receiver; transmitting a first wireless signal from the first transmitter along the wellbore at a first time; receiving the first wireless signal via the first receiver at a second time; determining a first elapsed time between the first time and the second time; and determining a first downhole position of the downhole tool based on the first elapsed time.

[0079] The method of Example A may further comprise at least one of: (1) estimating a speed of sound in a fluid to provide an estimated speed of the sound, the wellbore being filled with the fluid, the downhole tool being disposed in the fluid, and the first downhole position being determined based on the estimated speed of sound, optionally comprising (A) measuring a pressure in the wellbore with a pressure sensor to provide a measured pressure, the pressure sensor being disposed in the downhole tool; or measuring a temperature in the wellbore with a temperature sensor to provide a measured temperature, the temperature sensor being disposed in the downhole tool, and the estimated speed of sound being based on at least one of the measured pressure or the measured temperature; or (B) determining a pressure in the wellbore based on a pressure profile along the wellbore to provide a determined pressure;and determining a temperature in the wellbore based on a temperature profile along the wellbore to provide a determined temperature, the estimated speed of sound being based on at least one of the determined pressure or the determined temperature; (2) receiving a secondary signal via the downhole tool at a third time, the secondary signal being a reflection of the first wireless signal off a wellbore bottom, a downhole tubular, or another downhole object; determining a second elapsed time based on a difference between the third time and the first time; and refining the first downhole position of the downhole tool based on the second elapsed time; (3) transmitting a second wireless signal from a second transmitter along the wellbore at the first time;receiving the second wireless signal via the downhole tool at a fourth time; determining a third elapsed time based on a difference between the first time and the fourth time; and refining the first downhole position of the downhole tool based on the third elapsed time; (4) transmitting a second wireless signal along the wellbore from a second transmitter at a fifth time; receiving the second wireless signal via the downhole tool at a sixth time; determining a fourth elapsed time based on a difference between the fifth time and the sixth time; and refining the first downhole position of the downhole tool based on the fourth elapsed time.;

[0080] In one or more embodiments of Example A, the downhole tool further comprises at least one second receiver, and the second receiver is disposed further from the first transmitter than the first receiver, the method of Example A further comprising: receiving the first wireless signal via the second receiver at a seventh time; and determining a time delay between the second time and the seventh time, the estimated speed of sound being based on the time delay. In one or more embodiments of Example A, the disposing the downhole tool in the wellbore comprises pumping the downhole tool to the first downhole position. In one or more embodiments of Example A, the first wireless signal is transmitted through a fluid, a downhole tubular, or both; and / or the first wireless signal is one of an acoustic signal, a ping, or a continuous wave, and, optionally, receiving the first wireless signal produces a received signal, the method further comprises determining a phase shift between the first wireless signal and the received signal.

[0081] Example B: A system comprising: a first transceiver having a first clock; and a downhole tool disposed in a wellbore, the downhole tool comprising a second clock, a machine-readable medium, and a processor, the first clock being synchronized with the second clock, and the machine-readable medium comprising program code executable by the processor to cause the downhole tool to receive at a second time, via the downhole tool or the first transceiver, a first wireless signal transmitted at a first time, determine a first elapsed time between the first time and the second time, and determine a downhole position of the downhole tool based on the first elapsed time.

[0082] In one or more embodiments of Example B, the wellbore is filled with a fluid, the downhole tool is disposed in the fluid, the machine-readable medium further comprising program code for estimating a speed of sound in the fluid to provide an estimated speed of sound, and the downhole position being determined based on the estimated speed of sound. Optionally, in one or more embodiments of Example B, the downhole tool comprises at least one of a pressure sensor or a temperature sensor, and the estimated speed of sound being based on at least one of a pressure measured by the pressure sensor or a temperature measured by the temperature sensor.

[0083] The system of Example B may further comprise a second transceiver disposed at a known location, the machine-readable medium further comprising program code to: receive at a third time, via the downhole tool, a second wireless signal transmitted by the second transceiver, determine a second elapsed time between the first and third times, and refine the downhole position of the downhole tool based on the second elapsed time.

[0084] Example C: A method comprising: synchronizing a first clock with a second clock, the first clock being disposed in a downhole tool, the second clock being disposed in a first receiver, and the first receiver being disposed at a known location; disposing the tool downhole in a wellbore at a first location; transmitting a first wireless signal along the wellbore from the downhole tool at a first time; receiving the first wireless signal via the first receiver at a second time; determining a first elapsed time between the first time and the second time; and determining a first downhole position of the downhole tool based on the first elapsed time.

[0085] The method of Example C may further include receiving the first wireless signal via a second receiver at a third time, the second receiver being disposed in the wellbore; determining a second elapsed time between the first time and the third time; and refining the first downhole position of the downhole tool based on the second elapsed time.

Claims

Claims

1. A method (200), comprising: synchronizing (202) a first clock with a second clock, wherein the first clock is disposed in a first transmitter (170), wherein the first transmitter (170) is disposed at a known location, and wherein the second clock is disposed in a downhole tool (110, 410, 610); disposing (204) the downhole tool (110, 410, 610) in a wellbore (102), wherein the downhole tool (110, 410, 610) comprises a first receiver (150, 450, 650); transmitting (206) a first wireless signal from the first transmitter (170) along the wellbore (102) at a first time, wherein the first wireless signal is a continuous wave; receiving (208) the first wireless signal via the first receiver (150, 450, 650) at a second time, wherein receiving the first wireless signal produces a received signal;determining (210) a phase shift between the first wireless signal and the received signal; and determining (212) a first downhole position of the downhole tool (110, 410, 610) based on the phase shift.;

2. The method (200) of claim 1, further comprising estimating a speed of sound in a fluid to provide an estimated speed of sound, wherein the wellbore (102) is filled with the fluid, wherein the downhole tool (110, 410, 610) is disposed in the fluid, and wherein the first downhole position is refined based on the estimated speed of sound.

3. The method (200) of claim 2, further comprising at least one of: measuring a pressure in the wellbore (102) with a pressure sensor to provide a measured pressure, wherein the pressure sensor is disposed in the downhole tool (110, 410, 610); or measuring a temperature in the wellbore (102) with a temperature sensor to provide a measured temperature, in wherein the temperature sensor is disposed in the downhole tool (110, 410, 610), and wherein the estimated speed of sound is based on at least one of the measured pressure or the measured temperature.

4. The method (200) of claim 2, further comprising: determining a pressure in the wellbore (102) based on a pressure profile along the wellbore (102) to provide a determined pressure; and determining a temperature in the wellbore (102) based on a temperature profile along the wellbore (102) to provide a determined temperature, wherein the estimated speed of sound is based on at least one of the determined pressure or the determined temperature.

5. The method (200) of any one of claims 2 to 4, wherein the downhole tool (610) further comprises a second receiver (652), wherein the second receiver (652) is disposed further from the first transmitter (170) than the first receiver (650), the method further comprising: receiving the first wireless signal via the second receiver (652) at a seventh time; and determining a time delay between the second time and the seventh time, wherein the estimated speed of sound is based on the time delay.

6. The method (200) of any one of claims 1 to 5, wherein disposing the downhole tool (110, 410, 610) in the wellbore (102) comprises pumping the downhole tool (110, 410, 610) to the first downhole position.

7. The method (200) of any one of claims 1 to 6, further comprising: receiving a secondary signal via the downhole tool (410) at a third time, wherein the secondary signal is a reflection of the first wireless signal off a wellbore bottom (411), a downhole tubular, or another downhole object; determining a first elapsed time based on a difference between the third time and the first time; and refining the first downhole position of the downhole tool (410) based on the first elapsed time.

8. The method (200) of any one of claims 1 to 7, further comprising: transmitting a second wireless signal from a second transmitter (572) along the wellbore (102) at the first time; receiving the second wireless signal via the downhole tool (110) at a fourth time; determining a second elapsed time based on a difference between the first time and the fourth time; and refining the first downhole position of the downhole tool (110) based on the second elapsed time.

9. The method (200) of any one of claims 1 to 8, further comprising: transmitting a second wireless signal along the wellbore (102) from a second transmitter (572) at a fifth time; receiving the second wireless signal via the downhole tool (110) at a sixth time; determining a third elapsed time based on a difference between the fifth time and the sixth time; and refining the first downhole position of the downhole tool (110) based on the third elapsed time.

10. The method (200) of any one of claims 1 to 9, wherein the first wireless signal is transmitted through a fluid, a downhole tubular member, or both.

11. A system (100, 400, 500, 600, 700, 900) comprising: a first transceiver (170, 770) having a first clock; and a downhole tool (110, 410, 610, 710) disposed in a wellbore (102), the downhole tool (110, 410, 610, 710) comprising a second clock, a machine-readable medium, and a processor (1101), wherein the first clock is synchronized with the second clock, and wherein the machine-readable medium comprises program code executable by the processor (1101) to cause the downhole tool (110, 410, 610, 710) to receive at a second time, via the downhole tool (110, 410, 610, 710) or the first transceiver (170, 770), a first wireless signal transmitted at a first time, wherein the first wireless signal is a continuous wave and wherein receiving the first wireless signal produces a received signal, determining a phase shift between the first wireless signal and the received signal, and determining a downhole position of the downhole tool (110, 410, 610, 710) based on the phase shift.

12. The system (100, 400, 500, 600, 700, 900) of claim 11, wherein the wellbore (102) is filled with a fluid, wherein the downhole tool is disposed in the fluid, wherein the machine-readable medium further comprises program code for estimating a speed of sound in the fluid to provide an estimated speed of sound, wherein the determined downhole position is refined based on the estimated speed of sound, and, optionally, wherein the downhole tool (110, 410, 610, 710) comprises at least one of a pressure sensor or a temperature sensor, wherein the estimated speed of sound is based on at least one of a pressure measured by the pressure sensor, or a temperature measured by the temperature sensor.

13. The system (500) of claim 11 or 12, further comprising a second transceiver (572) disposed at a known location, wherein the machine-readable medium further comprises program code for: receiving at a third time, via the downhole tool (110), a second wireless signal transmitted by the second transceiver (572), determining an elapsed time between the first time and the third time, and refining the downhole position of the downhole tool (110) based on the elapsed time.

14. A method (800) comprising: synchronizing (802) a first clock with a second clock, wherein the first clock is disposed in a downhole tool (710), wherein the second clock is disposed in a first receiver (770), and wherein the first receiver (770) is disposed at a known location; disposing (804) the downhole tool (710) in a wellbore (102) at a first location; transmitting (806) a first wireless signal along the wellbore (102) from the downhole tool (770) at a first time, wherein the first wireless signal is a continuous wave; receiving (808) the first wireless signal via the first receiver (770) at a second time, wherein receiving the first wireless signal produces a received signal; determining (810) a phase shift between the first wireless signal and the received signal; and determining (812) a first downhole position of the downhole tool (710) based on the phase shift.

15. The method (800) of claim 14, further comprising: receiving the first wireless signal via a second receiver (972, 974) at a third time, wherein the second receiver is disposed in the wellbore; determining an elapsed time between the first time and the third time; and refining the first downhole position of the downhole tool (710) based on the elapsed time.

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