US20200232306A1

US20200232306A1 - Measuring Strain in a Work String During Completion Operations

Info

Publication number: US20200232306A1
Application number: US16/482,801
Authority: US
Inventors: William Brown-Kerr; Bruce Hermann Forsyth McGarian
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2017-03-28
Filing date: 2017-03-28
Publication date: 2020-07-23
Also published as: GB201912284D0; GB2574148A; AU2017407339A1; NO20191029A1; WO2018182578A1; RU2729087C1

Abstract

A device and method to measure strain in a work string during completion operations. The device can include a tubular body with multiple recesses in an outer surface, with strain sensors positioned in some of the recesses. The device can include a fluid pulser configured to communicate data received from the strain sensors to a surface controller via fluid pulse telemetry, with the fluid pulser positioned within one of the multiple recesses. The strain sensors can measure compression, tension, and/or rotational torque in the work string and communicate the sensed data to the surface for evaluation. The device can include a through-bore that extends through the body and has a substantially constant inner diameter for delivering a ball through the device to operate other downhole wellbore tools.

Description

TECHNICAL FIELD

The present disclosure generally relates to oilfield equipment and, in particular, to downhole tools, completion systems and techniques for measuring strain (e.g. torque, weight, etc.) in a work string.

BACKGROUND

In order to produce formation fluids from an earthen formation, wellbores can be drilled into the earthen formation to a desired depth for producing the formation fluids. After drilling a wellbore, casing strings can be installed in the wellbore providing stabilization to the wellbore and keeping the sides of the wellbore from caving in on themselves. Multiple casing strings can be used in completion of a deep wellbore. A small space between a casing and untreated sides of the wellbore (generally referred to as an annulus) can be filled with cement. After the casing is cemented in place, perforating gun assemblies can be used to form perforations through the casing and associated cement, and into the earthen formation.
Some casing strings are referred to as “liners” which are hung from an existing casing string at a desired location downhole. Setting a “liner” in the existing casing string may include imparting torque to a work string and applying weight from the work string to set the liner. The amount of torque and/or weight applied to the liner can be valuable information when setting a liner in an existing casing string.
Therefore, it will be readily appreciated that improvements in the arts of measuring torque and/or weight applied by a work string during completion operations are continually needed.

BRIEF DESCRIPTION OF THE DRAWINGS

Various embodiments of the present disclosure will be understood more fully from the detailed description given below and from the accompanying drawings of various embodiments of the disclosure. In the drawings, like reference numbers may indicate identical or functionally similar elements. Embodiments are described in detail hereinafter with reference to the accompanying figures, in which:

FIG. 1 is a representative partial cross-sectional view of a system for installing a liner in a wellbore, according to one or more example embodiments;

FIG. 2 is a representative partial cross-sectional view of a portion of the system in FIG. 1 with a measurement device and a running tool used to install a plug;

FIG. 3 is a representative partial cross-sectional view of a portion of the system in FIG. 1 with a measurement device and a running tool used to install a liner;

FIG. 4 is perspective view of the measurement tool shown in FIG. 3.

DETAILED DESCRIPTION OF THE DISCLOSURE

The disclosure may repeat reference numerals and/or letters in the various examples or Figures. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Further, spatially relative terms, such as beneath, below, lower, above, upper, uphole, downhole, upstream, downstream, and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the wellbore, the downhole direction being toward the toe of the wellbore. Unless otherwise stated, the spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the Figures. For example, if an apparatus in the Figures is turned over, elements described as being “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the exemplary term “below” can encompass both an orientation of above and below. The apparatus may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein may likewise be interpreted accordingly.
Moreover even though a Figure may depict a horizontal wellbore or a vertical wellbore, unless indicated otherwise, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in wellbores having other orientations including vertical wellbores, slanted wellbores, multilateral wellbores or the like. Likewise, unless otherwise noted, even though a Figure may depict an offshore operation, it should be understood by those skilled in the art that the method and/or system according to the present disclosure is equally well suited for use in onshore operations and vice-versa.
As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods also can “consist essentially of” or “consist of” the various components and steps. It should also be understood that, as used herein, “first,” “second,” and “third,” are assigned arbitrarily and are merely intended to differentiate between two or more objects, etc., as the case may be, and does not indicate any sequence. Furthermore, it is to be understood that the mere use of the word “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there be any “first” or “third,” etc.
The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, 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. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
Generally, this disclosure provides a measurement device and method to measure strain (such as compression or tension, and/or torque) in a work string during completion operations when securing a completion assembly to a casing in a wellbore. The completion assembly can be at least one of a liner, a liner hanger, a bridge plug, a frac plug, a whipstock, a packer, a sand screen, a milling tool, a fishing tool, a deflecting device, a completion device, an anchoring device, etc. The securing of the completion assembly to the casing (or other tubing strings in the wellbore) can include manipulations of the work string to impart strain on the completion assembly via the measurement tool, with the measurement tool measuring the strain being applied to the completion assembly. The measurement device can include a tubular body with multiple recesses in an outer surface, with strain sensors positioned in some of the recesses. The measurement device can include a telemetry device (such as a fluid pulser, an acoustic telemetry device, an electromagnetic telemetry device, an electrical signal telemetry device, and an optical telemetry device) configured to communicate data received from the strain sensors to a surface controller via telemetry, with the telemetry device positioned within one of the multiple recesses. The strain sensors can measure compression or tension, and/or rotational torque in the work string and communicate via the telemetry the sensed data to the surface for evaluation. The measurement device can include a through-bore that extends through the body and has a substantially constant inner diameter that allows a drop ball to pass through the measurement device and operate other downhole wellbore tools that are positioned further into the wellbore than the measurement device. As used herein, “drop ball” or “ball” refers to any object that can be displaced through the tubing string to actuate a downhole tool (e.g. running tool 24), where the object can be a ball, a dart, a plug, etc.
A casing string is tubing that is set inside a drilled wellbore to protect and support production of fluids to the surface. In addition to providing stabilization and keeping the sides of the wellbore from caving in on themselves, the casing string can protect fluid production from outside contaminants, such as separating any fresh water reservoirs from fluids being produced through the casing. Also known as setting pipe, casing a wellbore includes running pipe (such as steel pipe) down an inside of the recently drilled portion of the wellbore. The annulus between the casing and the untreated sides of the wellbore can be filled with cement to permanently set the casing in place. Casing pipe can be run from a floor of a rig, connected one joint at a time, and stabbed into a casing string that was previously inserted into the wellbore. The casing is landed when the weight of the casing string is transferred to casing hangers which are positioned proximate the top of the new casing, and can use slips or threads to suspend the new casing in the wellbore. A work string can be used to land the casing proximate a bottom end of the previously installed casing. A cement slurry can then be pumped into the wellbore and allowed to harden to permanently fix the casing in place. After the cement has hardened, the bottom of the wellbore can be drilled out, and the completion process continued.
Sometimes the wellbore is drilled in stages. The wellbore can be drilled to a certain depth, cased and cemented, and then drilled to a deeper depth, cased and cemented again, and so on. Each time the wellbore is cased, a smaller diameter casing is used. The widest type of casing can be called conductor casing, and is usually about 30 to 42 inches in diameter for offshore wellbores and 12 to 16 inches in diameter for onshore wellbores. An annular space radially outside the Conductor casing string can be filled with cement to prevent drilling fluids from circulating outside the conductor casing string and causing erosion. The next size in casing strings can be referred to as the surface casing, which can run several thousand feet in length. An annular space radially outside the Surface casing string can be filled with cement to prevent hydrocarbon fluids from encroaching into fresh water zones. In some wellbores, intermediate casing can be run to separate challenging areas or problem zones, such as areas of high pressure or lost circulation. An annular space radially outside the Intermediate casing string can be at least partially filled with cement to isolate formations which can possibly breakdown and cause a loss of circulation in the wellbore.
Generally, the last type of casing string run into the wellbore is the production casing string, and is therefore the smallest diameter casing string. The production casing string can be run directly into a producing reservoir. An annular space radially outside the Production casing string can be at least partially filled with cement to stop hydrocarbons from migrating to thief zones and to prevent sloughing of formations which can cause circulation loss in the wellbore. Additionally, a liner string can be run into the wellbore instead of a casing string. While a liner string is very similar to other casing strings in that it can be made up of separate joints of tubing, the liner string is not run the complete length of the wellbore. A liner string can be hung in the wellbore by a liner hanger, and then an annular space radially outside the liner string can be at least partially filled with cement. A production string can then be run in the wellbore to produce fluids to the surface and the rig.
FIG. 1 shows an elevation view in partial cross-section of a wellbore system 10 which can be utilized for completion operations in a wellbore 12. Wellbore 12 can extend through various earth strata in an oil and gas formation 14 located below the earth's surface 16. Wellbore system 10 can include a rig (or derrick) 18 and a wellhead 40. A conveyance 30 (e.g. segmented tubing string, coiled tubing etc.), can be used to convey completion tools and/or casing strings downhole. In the example shown in FIG. 1, the conveyance 30 can generally be referred to as a work string 30. The work string 30 can have a measurement device 50 attached to its lower end with a running tool 24 attached between the measurement device 50 and a liner 28. The running tool 24 can be attached to the liner 28 at the rig 18 and used to run the liner 28 into the wellbore 12 via the work string 30. As shown in FIG. 1, the running tool 24 is attached to the upper end of the liner 28 and the work string 30 is used to position the upper end of the liner 28 above, but proximate, a bottom end of the casing 34.
Once the liner 28 is correctly positioned in the wellbore 12, the running tool 24 can be used to set a liner hanger 21 (which may include packers and/or slips 20, 22) that will hold the liner 28 in position in the wellbore 12. Once the liner hanger 21 has been set, the running tool 24 can be released from the liner 28 and the work string 30, along with the measurement device 50 and the running tool 24, can be removed from the wellbore 12, leaving the liner 28 in the wellbore 12. However, prior to the work string 30 being removed from the wellbore 12, cement may be pumped through the work string 30, the measurement tool 50, and the running tool 24 to fill the annulus between the liner 28 and the wellbore 12. The packers and/or slips 20, 22 can be any suitable type of packer or slip that can securely fasten the top end of the liner 28 to the casing 34. For example, inflatable, swellable, compression, and/or mechanical packers can be included in the liner hanger 21. Also, mechanically extendable slips, hydraulically extendable slips, rotationally activated slips, etc. can also be included in the liner hanger 21. Packers and slips are well-known in the art and will not be discussed further.
FIG. 2 shows an embodiment of the current disclosure for setting a plug 90 in the wellbore 12. A fracturing operation is depicted in FIG. 2 with a fracture 94 having been formed at a stage 98 through perforations 86. To fracture stage 96, the previous fracture 94 is generally isolated from a new fracture 92 that can be formed through additional perforations 86 at the stage 96. In this completion operation of treating and/or fracturing the wellbore 12, a bridge plug or frac plug 90 can be installed in the wellbore 12 between stages 96 and 98 to divert a treatment fluid or a fracturing fluid into the perforations 86 at stage 96. The work string 30 can include the measurement device 50 and the running tool 24 attached to the end of the work string 30, with a plug 90 attached to the running tool. A centralizer 82 can be used to centralize the work string 30 in the wellbore 12. The plug 90 can be conveyed into the wellbore 12 via the work string 30 and set between stages 96 and 98 by the running tool 24. The measurement device 50 can measure compression, tension, and rotational torque applied to the plug 90 by the work string 30 as the plug is being set and possibly after the plug is set to test the integrity of the plug's seal to the casing 34 in the wellbore 12. As used herein the “plug” refers to a bridge plug, a frac plug, a whipstock, or any other device that can be run into the wellbore and set using the running tool 24.
FIG. 3 shows an embodiment of the current disclosure for setting a liner 28 in the wellbore 12, similar to the configuration shown in FIG. 1. The measurement device 50 can be connected to the running tool 24 via the threaded connections 54 and 56, with threaded connection 53 used to connect the measurement device 50 to the work string 30. It should be understood that other connections can be made by the threaded connections 53, 54, 56, such as additional segments of pipe can be connected between the measurement device 50 and the running tool 24, as well as between the measurement device 50 and the work string 30.
As stated previously, the running tool 24 can be attached to the top end of the liner 28. The liner 28 can be run into the wellbore 12 and positioned proximate a bottom end of the casing 34 (or any other desirable location along the casing string 34). The measurement device 50 can include multiple sensors for measuring and monitoring parameters such as downhole pressure, temperature, etc., as well as azimuthal orientation of the measurement device 50, torque applied to the running tool 24, and weight applied to the liner hanger by the running tool 24. The sensed data can be transmitted to the surface via mud pulse telemetry by a pulser 70 (see FIG. 4) included in the measurement device 50. This pulser 70 can be used to create negative pressure pulses in a fluid in the work string 30 that transmits the pulses to the surface. However, the pulser 70 does not restrict fluid flow in the through-bore 52 of the measurement device 50 to produce the mud pulse telemetry. The pulser 70 can selectively release fluid from the work string 30 into the annulus 32 to produce the negative mud pulses. The pulser 70 can include a receiver 104 and a transmitter 106 to receive and transmit telemetry data, respectively. The transmitter 106 can be powered off at desired times (such as when the work string is tripped in and/or out of the wellbore 12) to reduce power consumption of the measurement device 50. It should also be understood that various other telemetry devices 102 can be used to communicate data to the surface controller, such as an acoustic telemetry device, an electromagnetic telemetry device, and an electrical signal telemetry device, an optical telemetry device, etc. These types of telemetry devices are well-known in the art and will not be discussed further. However, it should be understood that none of these telemetry devices obstruct the through-bore 52 or otherwise reduce the inner diameter ID1 of the through-bore 52 in the measurement device 50.
Once the liner 28 is positioned in the wellbore 12, the liner hanger 21 can be set by expanding one or more packers 20 into contact with an inner surface of the casing string 34 and/or expanding slips 22 into engagement with the inner surface. There are many ways to set the liner hanger 21 and/or release the running tool 24 from the liner 28 after the liner 28 has been set. Some examples of setting the liner hanger 21 can be rotation of the running tool 24 by the work string 30, hydraulic activation of the running tool 24 by control lines, and/or a ball 48 drop. One benefit of the current measurement device 50 is that the through-bore 52 of the device allows for activating the hydraulics of the running tool 24 by dropping a ball 48 through the work string 30, through the measurement device 50, and into contact with a ball seat 42 in the running tool 24. The hydraulics of the running tool 24 can be operated when the ball 48 lands in the ball seat 42, thereby allowing manipulation of a pressure drop across the running tool 24. This pressure manipulation can be used to activate a liner hanger 21 setting operation of the running tool 24. Additionally, pressure manipulation(s) applied to the running tool 24 (as well as manipulations of the work string 30 applied to the running tool 24) can be used to produce a sequence that causes the running tool 24 to be released from the liner 28. Manipulations of the work string 30 can include compression (weight applied), tension (weight removed), and/or rotational torque to produce a sequence that operates the running tool 24.
When the liner hanger 21 is set, it may be desirable to test the integrity of the liner hanger 21 by application of weight on the liner 28. The weight on the liner 28 can be applied by applying a compression to the work string 30 which can be transmitted through the running tool 24 to the liner 28. If a predetermined amount of weight can be applied to the liner 28 without the liner failing, then the liner hanger 21 can be seen as being set properly. The amount of weight applied to the liner 28 can be determined by strain sensors 58, which can be positioned in recesses 61 in the outer surface 67 of the measurement device 50. As the compression of the work string 30 is applied, the measurement device 50 can measure the compression experienced by the device 50 and determine the amount of weight (or force) being applied to the liner 28 and thus to the liner hanger 21. The measured data can then be communicated to the surface controller 80 for evaluation.
The strain sensors 58 can be positioned circumferentially around an outside surface of the measurement device 50 at two or more positions that are spaced at an equal distance from each other. For example, FIGS. 2 and 3 have three sensors 58 positioned at “0,” “120,” and “240” degrees around the circumference of the body 66 (however, only one of the sensors 58 are shown). The strain sensors 58 can provide measurements of compression, tension, and/or torque, thereby determining the weight, tension, and/or rotational torque applied to the tool 24. The strain sensors 58 can be 3-axis strain gauges that can detect strain in a three axis orthogonal coordinate system of the measurement device 50.
The sensed data can be transmitted to the surface controller 80 via the mud pulse telemetry. When the sensed data is received at the surface, decisions can be made, such as to release the running tool 24 and remove the work string 30 from the wellbore 12 along with the measurement device 50. Additionally, if the sensed data reveals that the liner hanger 21 is not set properly, then corrective action can be taken to repair and/or retrieve it. The strain sensors 58 can provide visibility into completion operations when securing a completion assembly 100 to a casing in the wellbore 12. The completion assembly 100 can be at least one of a liner 28, a liner hanger 21, a bridge plug 90, a frac plug 90, a whipstock 90, a packer 20, a sand screen, a milling tool, a fishing tool, a deflecting device (such as for deflecting a tubing string, well tool, etc. into a lateral wellbore), a completion device (such as for fracturing, diversion, etc.), an anchoring device, etc. The securing of the completion assembly 100 to the casing 34 (or other tubing strings in the wellbore) can include manipulations of the work string 30 to impart strain on the completion assembly 100 via the measurement tool 50, with the measurement tool measuring the strain being applied to the completion assembly 100.
The measurement device 50 can include a tubular body 66, connector ends 53, 54, recesses 60, 61, 62 in an outer surface 67 of the body 66, with multiple sensors 64, 68 installed in the recesses 60, 62 and strain sensors 58 installed in the recesses 61. An internal flow passage can be formed as a single through-bore 52 with a substantially constant inner diameter ID1. As used herein, “substantially constant diameter” refers a diameter that may have some minor variations along a length of the through-bore, but the through-bore maintains the diameter for a majority of the length.
A ball 48 is shown in three possible positions as it travels through the measurement device 50 and into the running tool 24. Position 48a shows the ball 48 passing through the bore 52 in the measurement device 50. The ball 48 has an outer diameter OD1 that is less than the inner diameter ID1 of the through-bore 52. Since there are no obstructions to passage of the ball 48 through the device 50, the ball 48 is free to travel on to the running tool 24. Position 48b shows the ball 48 as it has entered the running tool 24 but prior to engaging the ball seat 42. A flow passage 38 can extend through the running tool 24 and can have an inner diameter ID2 that is also larger than the outer diameter OD1 of the ball 48. The ball 48 can travel until it lands in the ball seat 42, which has an inner diameter ID3 which is less than the outer diameter OD1 of the ball 48. The presence of the ball 48 in the ball seat 42 significantly restricts flow of fluid through the running tool 24, and allows a controller to manipulate pressure across the tool 24, which can be used to set the liner hanger 21 (e.g. set packer 20 and slips 22). The pressure manipulation across the tool 24 can also be used to release the tool 24 from the liner 28.
FIG. 4 shows a perspective view of the device 50 with various items secured in recesses 60, 61, 62 in the body 66 of the device 50. The fluid pulser 70, electrical connections 72, link blocks 74, electronics 76, sensors 64, 68, as well as strain sensors 58 can be positioned as shown in recesses in the outer surface 67 of the body 66. The enlarged portion of the body 66 of the device 50 allows these components to be installed in the device 50 without obstructing the through-bore 52 that extends through the device 50.
Thus, a measurement device 50 for measuring strain in a work string 30 during completion operations is provided. The measurement device 50 can include a body 66 with multiple recesses 60, 61, 62 in an outer surface 67 of the body 66, and strain sensors 58 that can detect compression, tension, and/or rotational torque of the body 66, where the strain sensors can be positioned in at least two of the multiple recesses 61, and where these recesses 61 are circumferentially spaced an equal distance apart from each other around a circumference of the body 66. The measurement device 50 can include a fluid pulser 70 (or other telemetry devices such as an acoustic telemetry device, an electromagnetic telemetry device, an electrical signal telemetry device, and an optical telemetry device) that can be configured to communicate data received from the strain sensors 58 to a surface controller 80 via fluid pulse telemetry (or other telemetry channels), with the fluid pulser 70 positioned within another one of the multiple recesses 60, 62. As stated above, the pulser 70 can include a receiver 104 and a transmitter 106 to receive and transmit telemetry data, respectively. The transmitter 106 can be powered off at desired times (such as when the work string is tripped in and/or out of the wellbore 12, long periods of inactivity, etc.) to reduce power consumption of the measurement device 50. The pulser 70 can also be other telemetry devices 102 that were stated above. A through-bore 52 with a substantially constant inner diameter ID1 can extend through the body 66 of the measurement device 50.
For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
The body 66 can have a threaded connection 53, 54 at each end of the device 50. The strain sensors 58 can be positioned in at least three of the multiple recesses 61, with the at least three recesses 61 circumferentially spaced an equal distance apart from each other around the circumference of the body 66. Pressure and temperature sensors 64, 68 can be positioned in other recesses 60, 62 of the multiple recesses 60, 61, 62, and provide their sensed data to the fluid pulser 70 (or other telemetry device) which is configured to communicate the pressure and temperature sensed data to the surface controller 80. The through-bore 52 can be configured to pass a ball 48 through the measurement device 50 and deliver the ball 48 to wellbore tools 24 located further into the wellbore 12 than the measurement device 50 for operating these wellbore tools 24.
A method for installing a completion assembly 100 in a wellbore 12 is provided, which can include operations of connecting the completion assembly 100 to a running tool 24, connecting the running tool 24 to a measurement device 50, connecting the measurement device 50 to a work string 30, and displacing the work string 30, thereby positioning the completion assembly 100 at a desired location in the wellbore 12.
The operations can also include commanding the running tool 24 to set the completion assembly 100, thereby securing the completion assembly 100 to a casing 34 in the wellbore 12, manipulating the work string 30 thereby causing compression or tension, and/or rotation in the work string 30 and causing strain to be applied to the running tool 24, measuring via the measurement device 50 the a force applied to the running tool 24, and determining that the force applied to the completion assembly 100 exceeds a pre-determined amount, thereby indicating that the completion assembly 100 is properly set.
For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
The operations can also include sensing via sensors 64, 68 pressure and/or temperature downhole and transmitting the sensed pressure and/or temperature data to a surface controller 80 via a fluid pulser 70 (or other telemetry device) in the measurement device 50. The completion assembly 100 can be at least one of a liner 28, a liner hanger 21, a bridge plug 90, a frac plug 90, a whipstock 90, a packer 20, a sand screen, a milling tool, a fishing tool, a deflecting device, a completion device, an anchoring device, etc.
The operations can also include sensing via sensors 58 compression or tension, and/or rotational torque in the measurement device 50 and transmitting the sensed compression or tension, and/or rotational torque data to a surface controller 80 via a telemetry device 70 included in the measurement device 50, where the telemetry device 70 can be of a fluid pulser 70, an acoustic telemetry device, an electromagnetic telemetry device, an electrical signal telemetry device, or an optical telemetry device.
The operations can also include displacing a ball 48 through the work string 30 to engage a ball seat 42 in the running tool 24, where the engagement of the ball 48 with the ball seat 42 can command the running tool 24 to set the completion assembly 100 and/or further command the running tool 24 to release the completion assembly 100 from the running tool 24. Engagement of the ball 48 in cooperation with manipulations of the work string 30 can be used to command the running tool 24 to release the completion assembly 100 from the running tool 24. The work string 30 manipulations can include applying compression or tension to the work string 30 as well as rotating the work string 30.
The operations can also include displacing the ball 48 through a through-bore 52 of the measurement device 50 before engaging the ball seat 42 in the running tool 24.
Another method for installing a completion assembly 100 in a wellbore 12 is provided, which can include operations of connecting the completion assembly to a running tool, connecting the running tool to a measurement device, connecting the measurement device to a work string, displacing the work string, thereby positioning the completion assembly at a desired location in the wellbore, during the displacing, a pulser of the measurement device is configured to a reduced power configuration, which consumes less power than a full power configuration of the pulser, and reconfiguring to the pulser to the full power configuration when a pre-determined condition occurs.
For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
The operations can also include commanding the running tool to set the completion assembly, thereby securing the completion assembly to a casing 34 (or other tubing string) in the wellbore 12, manipulating the work string 30 thereby causing strain in the work string 30 and causing a force to be applied to the running tool 24, measuring via the measurement device 50 the force applied to the running tool 24; and determining that the force applied to the completion assembly 100 exceeds a pre-determined amount, thereby indicating that the completion assembly 100 is properly set.
The pulser 70 can include a receiver 104 and a transmitter 106, with the reduced power configuration having the receiver 104 enabled to receive telemetry data and the transmitter 106 disabled to prevent transmission of telemetry data. This can conserve energy, since a portion of the measurement device 50 can be powered down, or at least put into a “sleep” mode that minimizes power consumption. This can be beneficial in the case where a battery is the power source for the measurement tool 50 and the wellbore 12 is several thousand feet deep. The time to displace the measurement device 50 to a desired position in the wellbore 12 can be several hours and/or days. Therefore, a reduced power configuration can extend the life of the battery.
The pulser 70 can include a receiver 104 and a transmitter 106, and the full power configuration can be where the receiver 104 is enabled to receive telemetry data and the transmitter 106 is enabled to transmit telemetry data.
The pre-determined condition can include when the completion assembly 100 is positioned at the desired location, or when the measurement tool detects a pre-determined threshold of strain, pressure, and/or temperature during displacement of the completion assembly 100 to a desired location in the wellbore 12.
The operations can also include reconfiguring the pulser 70 to the reduced power configuration via commands from the surface to the measurement device 50. This can be, for example, when the measurement tool 50 is being removed from the wellbore 12, a long period of time is desired between measurements, or any other reason to conserve energy consumption of the measurement tool 50.
Although various embodiments have been shown and described, the disclosure is not limited to such embodiments and will be understood to include all modifications and variations as would be apparent to one skilled in the art. Therefore, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed; rather, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the appended claims.

Claims

1. A measurement device for measuring strain in a work string during completion operations, the device comprising:

a body with multiple recesses in an outer surface of the body;

strain sensors that detect compression, tension, and/or rotational torque of the body, with the strain sensors positioned in at least two of the multiple recesses, and with the at least two recesses circumferentially spaced an equal distance apart from each other around a circumference of the body;

a fluid pulser that is configured to communicate data received from the strain sensors to a surface controller via fluid pulse telemetry, with the fluid pulser positioned within another one of the multiple recesses; and

a through-bore that extends through the body and has a substantially constant inner diameter.

2. (canceled)

3. The device of claim 1, wherein the strain sensors are positioned in at least three of the multiple recesses, with the at least three recesses circumferentially spaced an equal distance apart from each other around the circumference of the body.

4. The device of claim 1, further comprising pressure and temperature sensors positioned in other recesses of the multiple recesses.

5. The device of claim 4, wherein the pressure and temperature sensors provide their sensed data to the fluid pulser which is configured to communicate the pressure and temperature sensed data to the surface controller.

6. The device of claim 1, wherein the through-bore is configured to pass a ball through the measurement device and deliver the ball to wellbore tools located further into the wellbore than the measurement device.

7. A method of installing a completion assembly in a wellbore, the method comprising:

connecting the completion assembly to a running tool;

connecting the running tool to a measurement device;

connecting the measurement device to a work string;

displacing the work string, thereby positioning the completion assembly at a desired location in the wellbore;

commanding the running tool to set the completion assembly, thereby securing the completion assembly to a casing in the wellbore;

manipulating the work string thereby causing strain in the work string and causing a force to be applied to the running tool;

measuring via the measurement device the force applied to the running tool; and

determining that the force applied to the completion assembly exceeds a pre-determined amount, thereby indicating that the completion assembly is properly set.

8. The method of claim 7, further comprising sensing via sensors pressure and/or temperature downhole and transmitting the sensed pressure and/or temperature data to a surface controller via a fluid pulser in the measurement device.

9. The method of claim 7, wherein the completion assembly is a liner, a liner hanger, a bridge plug, a frac plug, a whipstock, a packer, a sand screen, a milling tool, a fishing tool, a deflecting device, a completion device, an anchoring device.

10. The method of claim 7, further comprising sensing via sensors compression, tension, and/or rotational torque in the measurement device and transmitting the sensed compression, tension, and/or rotational torque data to a surface controller via a telemetry device included in the measurement device.

11. The method of claim 10, wherein the telemetry device is selected from a group consisting of a fluid pulser, an acoustic telemetry device, an electromagnetic telemetry device, an electrical signal telemetry device, and an optical telemetry device.

12. The method of claim 7, wherein the commanding further comprises displacing a ball through the work string to engage a ball seat in the running tool, and wherein the engagement of the ball with the ball seat commands the running tool to set the completion assembly.

13. The method of claim 12,

wherein the engagement of the ball further commands the running tool to release the completion assembly from the running tool; and

wherein the engagement of the ball in cooperation with manipulations of the work string commands the running tool to release the completion assembly from the running tool.

14. (canceled)

15. The method of claim 13, wherein work string manipulations include at least one of applying compression, tension and rotational torque to the work string.

16. The method of claim 12, wherein displacing the ball further comprises displacing the ball through a through-bore of the measurement device before engaging the ball seat in the running tool.

17-20. (canceled)

21. A method of installing a completion assembly in a wellbore, the method comprising:

connecting the completion assembly to a running tool;

connecting the running tool to a measurement device;

connecting the measurement device to a work string;

during the displacing, a pulser of the measurement device is configured to a reduced power configuration, which consumes less power than a full power configuration of the pulser; and

reconfiguring to the pulser to the full power configuration when a pre-determined condition occurs.

22. The method of claim 21, further comprising,

measuring via the measurement device the force applied to the running tool; and

23. The method of claim 21, wherein the pulser comprises a receiver and a transmitter, and wherein the reduced power configuration has the receiver enabled to receive telemetry data and the transmitter disabled to prevent transmission of telemetry data.

24. The method of claim 21, wherein the pulser comprises a receiver and a transmitter, and wherein the full power configuration has the receiver enabled to receive the telemetry data and the transmitter enabled to transmit the telemetry data.

25. The method of claim 22, wherein the pre-determined condition comprises the completion assembly being positioned at the desired location and/or one of the measurement tool detecting a pre-determined threshold of strain, pressure, and/or temperature during the displacing.

26. The method of claim 21, further comprising reconfiguring the pulser to the reduced power configuration via commands from the surface to the measurement device.