US20150107855A1

US20150107855A1 - Device that undergoes a change in specific gravity due to release of a weight

Info

Publication number: US20150107855A1
Application number: US14/472,006
Authority: US
Inventors: Zachary R. MURPHREE; Michael L. Fripp; Zachary W. WALTON
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2013-10-23
Filing date: 2014-08-28
Publication date: 2015-04-23

Abstract

A method of performing an operation in a wellbore using a device, the method comprises: introducing the device into the wellbore, wherein the device initially comprises a body and a weight; causing or allowing the weight to become disassociated from the body, wherein after disassociation, the device comprises the body, and wherein the specific gravity of the device decreases after the weight becomes disassociated from the body; and causing or allowing at least the body to move towards a wellhead of the wellbore after the weight is disassociated from the body.

Description

TECHNICAL FIELD

Devices for use in performing oil or gas operations may need to be removed from the wellbore after use. The devices can be a tool, an isolation device, or a communication device. The device can be returned to the surface of the well after use to restore fluid communication within the wellbore or to retrieve information from the communication device.

BRIEF DESCRIPTION OF THE FIGURES

The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments.

FIG. 1 is a schematic illustration of a well system containing more than one device, wherein the devices are isolation devices.

FIG. 2 is a schematic illustration of a well system wherein the device is a tool and a weight is attached to the tool via a tether.

FIG. 3 is a schematic illustration of a well system containing more than one device, wherein the devices are used to collect information about one or more parameters of the well system.

FIG. 4 is a schematic illustration of a well system showing the weight becoming disassociated from a body of the device via a phase change of a connector.

FIGS. 5A-5C are schematic illustrations of the device containing a different first material making up the body of the device and the weight according to an embodiment.

FIG. 6 is a schematic illustration of the device illustrating attachment of the weight to the body of the device according to an embodiment.

FIG. 7 is a schematic illustration of the device illustrating attachment of the weight to the body of the device according to another embodiment.

DETAILED DESCRIPTION

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.
It should be understood that, as used herein, “first,” “second,” “third,” etc., are arbitrarily assigned and are merely intended to differentiate between two or more devices, materials, etc., as the case may be, and does not indicate any particular orientation or sequence. Furthermore, it is to be understood that the mere use of the term “first” does not require that there be any “second,” and the mere use of the term “second” does not require that there be any “third,” etc.
As used herein, a “fluid” is a substance having a continuous phase that tends to flow and to conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas.
As used herein, the relative term “downstream” and “downward” means at a location further away from a wellhead. As used herein, the relative term “upstream” and “upward” means at a location closer to the wellhead.
Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil, gas, or water is referred to as a reservoir. A reservoir may be located on land or off shore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, and/or water produced from the wellbore is called a reservoir fluid.
A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. The wellbore is drilled into and penetrates a subterranean formation. The subterranean formation can be a part of a reservoir or adjacent to a reservoir. A wellbore can include vertical, inclined, and/or horizontal portions, and it can be straight, curved, and/or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, “into a well” means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.
A portion of a wellbore may be an open hole or cased hole. In an open-hole wellbore portion, a tubing string may be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore, which can also contain a tubing string. A wellbore can contain one or more annuli. Examples of an annulus include, but are not limited to: the space between the wall of the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wall of the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a first tubing string and the outside of a second tubing string, such as a casing.
It is often desirable to remove a device from a wellbore after use. By way of example, it is often desirable to remove an isolation device after zonal isolation is no longer needed. Zonal isolation can be used in a variety of wellbore operations, especially for wellbores that extend several hundreds of feet or several thousands of feet into a subterranean formation. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fissures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of an isolation device. An isolation device can be used for zonal isolation and functions to block fluid flow within a tubular, such as a tubing string, or within an annulus. The isolation devices can be used to create multiple intervals of the wellbore. There can be one or more intervals of the wellbore that correspond to a zone of the subterranean formation. The blockage of fluid flow prevents the fluid from flowing across the isolation device in any direction and isolates the formation zone of interest. In this manner, treatment techniques can be performed within the zone of interest.
A common isolation device is a ball and a seat (commonly called a baffle). It is to be understood that reference to a “ball” is not meant to limit the geometric shape of the ball to spherical, but rather is meant to include any device that is capable of engaging with a baffle. A “ball” can be spherical in shape, but can also be a dart, a bar, or any other shape. The baffle is attached to the inside of a tubing string, for example a casing. Zonal isolation can be accomplished via the ball and baffle by dropping or flowing the ball from the wellhead onto the baffle that is located within the wellbore. The ball engages with the baffle, and the seal created by this engagement prevents fluid communication into other zones downstream of the ball and baffle within the tubing string. In order to treat more than one zone using a ball and baffle, the wellbore can contain more than one baffle. For example, a baffle can be located within each wellbore interval. Generally, the inner diameter (I.D.) of the tubing string where the baffles are located is different for each interval. For example, the I.D. of the tubing string sequentially decreases at each interval, moving from the wellhead to the bottom of the well. In this manner, a smaller ball is first dropped into a first interval that is the farthest downstream; that zone is treated; a slightly larger ball is then dropped into another interval that is located upstream of the first interval; that zone is then treated; and the process continues in this fashion—moving upstream along the wellbore—until all the desired zones have been treated.
A bridge plug is composed primarily of slips, a plug mandrel, and a rubber sealing element. A bridge plug can be introduced into a wellbore and the sealing element can be caused to block fluid flow into downstream zones. A packer generally consists of a sealing device, a holding or setting device, and an inside passage for fluids. A packer can be used to block fluid flow through the annulus located between the outside of a tubular and the wall of the wellbore or inside of a casing.
Isolation devices can be classified as permanent or retrievable. While permanent isolation devices are generally designed to remain in the wellbore after use, retrievable devices are capable of being removed after use. It is often desirable to use a retrievable isolation device in order to restore fluid communication between one or more intervals after zonal isolation is no longer needed. Traditionally, isolation devices are retrieved by inserting a retrieval tool into the wellbore, wherein the retrieval tool engages with the isolation device, attaches to the isolation device, and the isolation device is then removed from the wellbore. Another way to remove an isolation device from the wellbore is to mill at least a portion of the device. Yet, another way to remove an isolation device is to contact the device with a solvent, such as an acid, thus dissolving all or a portion of the device.
However, some of the disadvantages to using traditional methods to remove a retrievable isolation device include: using a retrieval tool can be difficult and time consuming; milling can be time consuming and costly; and premature dissolution of the isolation device can occur. For example, premature dissolution can occur if acidic fluids are used in the well prior to the time at which it is desired to dissolve the isolation device.
Another example of when it is desirable to remove a device from a wellbore is for information communication. A communication device can be placed into the wellbore to send a command to one or more downhole tools. The communication device can then be returned to the surface after the commands have been received. Moreover, a communication device can also collect information from one or more sensors located within the wellbore. The communication device can then be returned to the surface where the information is retrieved from the communication device. The communication device can also contain a sensor that collects information about one or more parameters of the wellbore. It can be difficult to remove a communication device from a wellbore, especially if the wellbore is not producing a reservoir fluid because the device may have too much weight to be retrievable.
Yet another example of when it is desirable to remove a device from a wellbore is after a tool completes a specific function. There are a multitude of tools used in the oil and gas industry, such as a setting tool, retrieval tool, shifting tool, etc. that are most often returned to the surface after the tool has completed its intended function.
There exists a need to more easily and efficiently remove a device from a wellbore after a desired period of time. Some of the prior attempts to solve this problem include dissolving or liquefying some, or all, of the device. However, there is also a need for a portion of the device to remain intact such that some of the device can be returned to the wellhead. A novel method of removing a device from a wellbore includes connecting a weight to a body of the device. The increased specific gravity the weight imparts to the body helps the device to be pumped or sink to the desired location in the wellbore. After the intended use of the device is no longer needed, the weight can become disassociated or disconnected from the body of the device. The specific gravity of the device therefore decreases, which allows at least the body of the device to float, be pulled, or be produced to the wellhead of the wellbore.
According to an embodiment, a method of performing an operation in a wellbore using a device, the method comprising: introducing the device into the wellbore, wherein the device comprises a body and a weight; causing or allowing the weight to become disassociated from the body, wherein the specific gravity of the device decreases after the weight becomes disassociated from the body; and causing or allowing at least the body to move towards a wellhead of the wellbore after the weight is disassociated from the body.
According to another embodiment, a system for performing an operation in a wellbore using a device, the system comprising: the device, wherein the device comprises a body and a weight; and the wellbore; wherein the device is located within the wellbore, wherein the body is directly or operatively connected to the weight, and wherein the specific gravity of the device decreases after the weight becomes disconnected from the body.
Any discussion of the embodiments regarding the device or any component related to the device (e.g., the weight) is intended to apply to all of the method and system embodiments.
Turning to the Figures, FIG. 1 depicts a well system 10. The well system 10 can include at least one wellbore 11. The wellbore 11 can penetrate a subterranean formation 20. The subterranean formation 20 can be a portion of a reservoir or adjacent to a reservoir. The wellbore 11 can include a casing 12. The wellbore 11 can include both vertical and horizontal wellbore sections or can include only a generally vertical wellbore section or can include only a generally horizontal wellbore section. One or more sections of tubing string 15 can be installed in the wellbore 11. The subterranean formation 20 can include one or more zones. The well system 10 can comprise at least a first wellbore interval 13 and a second wellbore interval 14. At least one wellbore interval can correspond to a particular formation zone. The well system 10 can also include more than two wellbore intervals, for example, the well system 10 can further include a third interval, a fourth interval, and so on. The well system 10 can further include one or more packers 18. The packers 18 can be used in addition to an isolation device to isolate each interval of the wellbore 11. The packers 18 can be used to help prevent fluid flow between one or more wellbore intervals (e.g., between the first interval 13 and the second interval 14) via an annulus 19. The tubing string 15 can also include one or more ports 17. One or more ports 17 can be located in each section of the tubing string. Moreover, not every section of the tubing string needs to include one or more ports 17. For example, a first section of tubing string 15 can include one or more ports 17, while a second section of tubing string does not contain a port. In this manner, fluid flow into the annulus 19 for a particular section can be selected based on the specific oil or gas operation to be performed.
It should be noted that the well system 10 illustrated in the drawings and described herein is merely one example of a wide variety of well systems in which the principles of this disclosure can be utilized. It should be clearly understood that the principles of this disclosure are not limited to any of the details of the well system 10, or components thereof, depicted in the drawings or described herein. Furthermore, the well system 10 can include other components not depicted in the drawing. For example, the well system 10 can further include a well screen. By way of another example, cement may be used instead of packers 18 to provide zonal isolation. Cement may also be used in addition to packers 18.
The methods include performing an operation in the wellbore 11. The operation can be any of a variety of operations that are commonly performed in a wellbore, including, but not limited to, logging a well, stimulation treatments such as fracturing or acidizing treatments, perforating a casing, completion operations using tools, and information communication. One advantage to using the embodiments disclosed herein for logging, is that a logging device, such as a communications ball can be introduced into the wellbore without the need for traditional logging equipment such as wireline or coiled tubing, which can add to the expense.
According to an embodiment, the device is an isolation device. The isolation device can be at least partially capable of restricting or preventing fluid flow between a first wellbore interval 13 and a second wellbore interval 14. By way of example, the isolation device can be used to restrict or prevent fluid flow between different intervals within the tubing string 15 while packers 18 and/or cement can be used to restrict or prevent fluid flow between different intervals within the annulus 19. The isolation device can also be the only device used to prevent or restrict fluid flow between intervals. By way of another example, there can also be two or more isolation devices positioned within a given interval. According to this example, one isolation device can be a packer while the other isolation device can be a ball and baffle or a bridge plug. Examples of isolation devices capable of restricting or preventing fluid flow between zones include, but are not limited to a ball, a plug, a bridge plug, a wiper plug, and a packer.
The device 30 can be a ball, wherein the ball can engage a baffle 31 to provide zonal isolation. The ball can engage a sliding sleeve 50 during placement. This engagement with the sliding sleeve 50 can cause the sliding sleeve to move; thus, opening a port 17 located adjacent to the baffle. The port 17 can also be opened via a variety of other mechanisms instead of a ball. The use of other mechanisms may be advantageous when the isolation device is not a ball. After placement of the isolation device, fluid can be flowed from, or into, the subterranean formation 20 via one or more opened ports 17 located within a particular wellbore interval. As such, a fluid can be produced from the subterranean formation 20 or injected into the formation.
The device 30 includes a body 40. The device 30 can be any device that is used in oil or gas operations, whereby at least the body of the device can be returned to the wellhead after use. By way of example, FIG. 1 illustrates an isolation device, FIG. 2 illustrates a tool as the device, and FIGS. 3 and 4 illustrate a communication device. The tool can be, for example, a setting tool, retrieval tool, or a shifting tool.
A communication device can be very useful to communicate information from the surface to a downhole tool or other component or communicate information about a downhole parameter to the surface. By way of example, the device 30 can include a receiver or an antenna for collecting information from one or more sensors located downhole. By way of another example, the device 30 can also include one or more sensors located in the body 40 of the device. The sensors can collect information about a downhole parameter, such as temperature, pressure, the oil to water ratio of a wellbore or reservoir fluid, the flow rate of a producing reservoir fluid, among other numerous other parameters of the wellbore or subterranean formation. One of ordinary skill in the art will be able to select the appropriate sensor(s) depending on the parameter of interest to be ascertained. By way of yet another example, the body 40 of the device 30 can include a transmitter for transmitting a command to one or more downhole tools or downhole components. The command could be, for example, shifting a sliding sleeve into an open or closed position. The communication device can utilize a variety of information communication schemes, such as acoustic, electromagnetic, magnetic, or pressure pulse telemetry. For example, the information communication device can include a Radio Frequency Identification tag “RFID” tag or a Near Field Communication tag “NFC” tag.
As can be seen in the Figures, the device 30 includes the body 40. The device 30 can include other components, such as sensors, antennae, etc. discussed above (not shown). The body 40 can be made from a first material 44. The first material 44 can be a solid, a liquid, a gas, or combinations thereof (e.g., a foam or mist), depicted in FIGS. 5A-5C, respectively. The liquid could be, for example, an oil or water. For a liquid, gas, or combination fluid as the first material 44, then the body 40 can include an enclosure 43 for the first material 44. The enclosure 43 can be made from a variety of materials and can be relatively rigid or very flexible. By way of example, the enclosure 43 can be a hollow metal or metal alloy ball, or it can be a flexible plastic or rubber bladder. For the hollow metal or metal alloy ball, the metal selected can preferably be a light-weight metal such as magnesium or aluminum. The exact shape and thickness of the enclosure 43 can vary and can be selected based in part, on the type of device (i.e., an isolation device, tool, or communication device).
The first material 44 and/or the enclosure 43 can be selected from the group consisting of a metal, a metal alloy, a plastic, a ceramic, or an elastomer. The density of the first material can be modified by adding a syntactic foam, a liquid, a gas, gas-filled spheres, low-density porous microspheres, fibers, other low-density materials, and combinations thereof. According to an embodiment, the body 40 has a specific gravity less than the specific gravity of the fluid located in the wellbore. In this manner, without the weight, the body 40 would be capable of floating to the top of the column of fluid. Wellbore fluids can have a specific gravity in the range of about 0.7 to over 1.2. According to another embodiment, the body 40 has a specific gravity less than 1.1, more preferably less than 0.8 at a temperature of 71° F. (22° C.) and a pressure of 1 atmosphere (atm).
The device 30 also includes the weight 41. According to an embodiment, the body 40 is directly or operatively connected to the weight 41. The body 40 can also be associated with the weight 41. Preferably, the body 40 is connected to the weight 41 at least prior to and during introduction of the device 30 into the wellbore. The weight can be made from a more dense substance. The substance the weight is made of can have a specific gravity of at least 3, preferably in the range of about 3 to about 10 at a temperature of 71° F. (22° C.) and a pressure of 1 atmosphere. The device 30 can have a predetermined ratio of the first material 44 and possibly the enclosure 43 of the body 40 and the substance of the weight 41. The ratio can vary and can be selected such that the device 30 has a desired overall specific gravity prior to and during introduction into the wellbore wherein the body and the weight are connected, either directly or indirectly. In this manner, the weight 41 increases the overall specific gravity of the device 30 during introduction into the wellbore and facilitates the device 30 being pumped or sinking to the desired wellbore location. According to an embodiment, the ratio is selected such that the device has a specific gravity greater than 1.1 prior to and during introduction into the wellbore and while the weight is associated or connected to the body.
The substance of the weight 41 can be degradable or non-degradable. According to an embodiment, the substance of the weight 41 is degradable when the weight 41 is directly connected to the body 40. According to another embodiment, the substance of the weight 41 is non-degradable when the weight 41 is indirectly connected to the body 40. Examples of suitable non-degradable substances for the weight 41 include, but are not limited to, metals such as tungsten, iron, sand, ceramic, and metal alloys such as steel. Examples of suitable degradable substances include, but are not limited to substances capable of undergoing: a phase transformation (e.g., from a solid to a liquid) via a change in temperature or dissolution; chemical decomposition via a change in pH; or galvanic corrosion. The substance, for example, a thermoplastic, can melt as the temperature of the wellbore increases above the glass transition or melting temperature of the substance.
The substance of the weight 41 can be a fusible alloy such as a eutectic, or a hypo- or hyper-eutectic composition. A fusible alloy is a mixture of two or more substances that undergoes a solid-liquid phase transformation at a lower temperature than any other composition made up of the same substances. Stated another way, the temperature at which a fusible alloy undergoes the solid-liquid phase transformation is a lower temperature than any composition made up of the same substances can freeze or melt at and is referred to as the eutectic temperature. A solid-liquid phase transformation temperature can also be referred to as the freezing point or melting point of a substance or composition. The substances making up the fusible alloy can be compounds, such as metal alloys or thermoplastics, or metallic elements. The fusible alloy undergoes the solid-liquid phase transformation at a temperature that is lower than the solid-liquid phase transformations of at least one of the individual substances making up the composition. The solid-liquid phase transformation temperature can be greater than one or more of the individual substances making up the composition, but should be less than at least one of the substances. By way of example, the melting point of bismuth at atmospheric pressure (101 kilopascals) is 520° F. (271° C.) and the melting point of lead is 621° F. (327° C.); however, the melting point of a composition containing 55.5% bismuth and 44.5% lead has a melting point of 244° F. (118° C.). As can be seen the bismuth-lead composition has a much lower melting point than either elemental bismuth or elemental lead.
The substance of the weight 41 can also be selected such that it undergoes galvanic corrosion in the presence of an electrolyte. Galvanic corrosion occurs when dissimilar metals or metal alloys having different electrode potentials come in contact with an electrolyte and an electrically-conductive path exists between the dissimilar metals. One of the metals acts as an anode and the other as the cathode. The anode metal dissolves into the electrolyte, and deposit collects on the cathodic metal. The anodic metal or metal alloy can be the substance of the weight 41. The cathodic metal can be positioned nearby the weight 41, for example, it can be part of a baffle, the tubing string, or casing. In this manner, the weight 41 can corrode when positioned at the desired wellbore location. Preferably, the metal and the metal of the metal alloy are non-toxic.
If the weight 41 is indirectly connected to the body 40 via a tether or connector 45, then preferably the tether or connector is made from a degradable substance. The degradable substance for the tether or connector 45 can be selected from the same substances disclosed for the degradable weight 41. Examples of other suitable substances for the tether or connector 45 include, but are not limited to, polymers such as polylactic acid (PLA), polyglycolic acid (PGA), carbohydrates or sugars, natural rubbers, silk, borate glass, salt, or thermoplastics. In this manner, the tether or connector 45 can degrade and release the weight 41 from association or connection with the body 40 of the device 30.
The methods include causing or allowing the weight 41 to become disassociated from the body 40, wherein the specific gravity of the device 30 decreases after the weight 41 becomes disassociated from the body 40. Disassociation can be a result of the weight becoming disconnected from the body. As can be seen in FIG. 2, the weight 41 can be indirectly connected to the body 40 of the tool device 30 via a tether or connector 45. In this manner, as the tool is run into the wellbore on a wireline or slickline 16, the tool will more easily fall to the desired location in the wellbore 11 due to the weight 41 being associated with the body 40. After the tool is no longer needed in the wellbore, the tether or connector 45 can degrade whereby the weight 41 becomes disassociated from the body 40 of the tool. The methods also include causing or allowing at least the body to move towards the wellhead of the wellbore after the weight is disassociated from the body. According to the embodiment illustrated in FIG. 2, now that the specific gravity of the tool has decreased after the weight 41 is disconnected from the body 40, the tool is much easier to remove from the wellbore. As such, an operator at the surface of the well can cause the tool to move towards the wellhead via application of an upward force on the wireline or slickline 16.
FIG. 3 illustrates more than one communication device 30 located in the wellbore 11. Each of the communication devices 30 can include one or more sensors for determining at least one downhole parameter (discussed above) within the body 40 of the communication devices 30. The sensors can determine the same parameter or different parameters. Each of the communication devices 30 can be associated with or connected to the weight 41, which is depicted in FIG. 3 as the tubing string 15, via the tether or connector 45. The exact spacing and location of each communication device 30 can be predetermined and can vary. The tether or connector 45 can be made from a degradable substance such that after degradation, at least the body 40 of the communication devices 30 can flow or be produced toward the wellhead of the wellbore. The amount of time necessary to degrade the degradable substance of the tether or connector 45 can vary between the different communication devices 30. By way of example, it may be desirable to return the communication device 30 located further away from the wellhead and then moving in a successive fashion upwards towards the wellhead, releasing the next communication device and so on. Alternatively, it may be desirable to release the communication devices 30 starting closer to the wellhead and then working downward in successive fashion. The length, thickness, etc. can be selected for each of the tethers or connectors 45 so the substance will degrade in the desired amount of time for a specific communication device. The substance selected can also vary to allow the tether or connector 45 to degrade in the desired amount of time. By way of example, a tether or connector 45 located further down in the wellbore may be made from a specific fusible alloy that melts at a temperature at that location in the wellbore; whereas, a different tether or connector located closer to the wellhead may be made from a different fusible alloy having a different phase transformation range. In this manner, the time required for the substance of each tether or connector 45 to degrade can be preselected and vary depending on the specific conditions for the exact well. The time can range from an hour to several days or even weeks. As such, there can be information communication from the wellbore to operators at the surface over a desired time period.
FIG. 4 illustrates a communication device 30 being introduced into the wellbore 11 and being returned towards the wellhead. As can be seen, the weight 41 is indirectly connected to the body 40 of the communication device 30 via a threaded connector 45. As the communication device 30 is introduced into the wellbore 11, the weight 41 helps the communication device 30 to sink or be pumped away from the wellhead. The body 40 of the communication device 30 can include one or more sensors, antennae, or transmitters for communicating with downhole tools or components via RFID coupling or Near Field Communication or collecting information about one or more downhole parameters of interest. As the communication device 30 continues downward through the tubing string 15, as depicted by the arrows, the substance of the connector 45 starts to degrade. Degradation of the connector 45 continues until the weight 41 is no longer connected to the body 40 of the communication device 30. After disassociation from the body 40, the weight 41 will tend to continue to sink towards the bottom of the wellbore due to the mass of the weight 41 being much greater than the mass of the body 40. Of course, after disassociation, the weight 41 can be flowed or move towards the wellhead depending on the exact specific gravity of the substance making up the weight 41 and the exact density of the wellbore or reservoir fluid. Also, after disassociation, the body 40 can move towards the wellhead of the wellbore due to the decrease in the specific gravity of the communication device 30. The body 40 can move towards the wellhead via floatation or via production of a reservoir fluid. An operator at the surface can then retrieve the information from the body of the communication device. It is to be understood that even though it is not depicted in the drawing, the communication device can flow in a reverse direction through the wellbore. For example, the device can be introduced into the annulus 19 (shown in FIG. 1) and be returned up through the inside of the tubing string 15, such as a production tubing string.
FIGS. 5A-7 depict connection of the weight 41 to the body 40 according to different embodiments. As discussed earlier, the body 40 of the device 30 can be made from a first material 44, and for a liquid, gas, or combination liquid/gas, then the first material 44 can be located within the enclosure 43. The weight 41 is depicted in FIGS. 5A-5C as being composed of several discreet bodies. The bodies can be various shapes and cross-sectional sizes. The weight 41 is depicted as being shaped and sized as BBs, pellets, or shot. Of course, the bodies of the weight 41 do not have to be spherical in shape. The weight 41 depicted in FIGS. 5A-5C as several discreet bodies may be useful when due to the specific gravity of the substance making up the weight 41, the weight may be very difficult to return to the wellhead. In this instance, it may be undesirable to have one larger weight 41 that may block fluid flow after disassociation from the body 40 or otherwise impair oil or gas operations. Accordingly, it may be desirable to utilize discreet bodies as the weight 41 so as not to impair operations. The bodies of the weight 41 can be connected to the body 40 via a binding matrix 46. The binding matrix 46 can not only bind the bodies of the weight together, but also indirectly connects the weight bodies to the body 40. The binding matrix 46 can be made from any of the degradable substances discussed above. The bodies of the weight can be non-degradable or be degradable on a different time scale.
The weight 41 can be directly connected to the body 40 similar to the illustration in FIG. 6 except without the tether or connector 45. According to this embodiment, the weight 41 can be cap-like and directly affixed, for example with a glue or other adhesive, to the body 40. As shown in FIG. 6, the weight 41 can be connected to the body 40 via a threaded, bonded, interference, snap-ring, or adhesive connection via the tether or connector 45. Accordingly, the body can contain a corresponding mating hole for receiving the connector 45. The tether or connector 45 can indirectly connect the weight 41 with the body 40 as shown in FIG. 7. This embodiment may be useful when the enclosure 43 is a bladder made from a flexible material such as a plastic or rubber. In this embodiment, at least one outer surface of the enclosure 43 that forms the body 40 can be directly connected to the tether or connector 45 with the weight 41 being indirectly connected to the body 40.
The methods include causing or allowing the weight 41 to become disassociated from the body 40. The step of causing can include any action on an operator's part that causes the weight 41 and/or the tether or connector 45 to degrade. As used herein, the term “degrade” means any physical change to the substance making up the component that causes the component to become disassociated from another component, including, but not limited to, melting, dissolving, breaking apart into discreet particles, becoming a semi-liquid, etc. The step of causing can include without limitation, introducing a heated fluid, an electrolyte, an acid or a base, or a solvent into the wellbore to come in contact with the degradable substance. The step of allowing can be useful when the wellbore already contains a fluid necessary to cause degradation of the substance or the temperature around the device is sufficient to cause a phase change of the substance. By way of example, the tether or connector can be stable in a completion fluid, but when allowed to come in contact with a production fluid, the production fluid can cause the weight to become disassociated from the body via degradation of the tether or connector in the production fluid.
The methods also include causing or allowing at least the body 40 to move towards the wellhead of the wellbore 11 after the weight 41 is disassociated from the body 40. The step of causing can include circulating a wellbore fluid towards the wellhead, introducing a fluid into the wellbore having a sufficient density such that the body 40 is capable of moving towards the wellhead, or producing a fluid from the subterranean formation. The step of allowing can be used when the density of the wellbore fluid is low enough that the body 40 will float or become buoyant in the fluid and move on its own towards the wellhead. Depending on the specific gravity of the substance making up the weight 41, the weight may also move towards the wellhead. There may be other components, either included within the body 40 or are part of the device 30 that may also move towards the wellhead.
The methods can further include producing a reservoir fluid from the wellbore. The methods can also include monitoring parameter(s) of wellbore fluids, components of the wellbore, or the subterranean formation via the device 30. The methods can also include sending one or more commands downhole via the device 30. The methods can also include using the device 30 to create one or more wellbore intervals. The methods can also include using the tool device 30 to perform one or more functions downhole.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. 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. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, 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.

Claims

What is claimed is:

1. A method of performing an operation in a wellbore using a device, the method comprising:

introducing the device into the wellbore, wherein the device initially comprises a body and a weight;

causing or allowing the weight to become disassociated from the body, wherein after disassociation, the device comprises the body, and wherein the specific gravity of the device decreases after the weight becomes disassociated from the body; and

causing or allowing at least the body to move towards a wellhead of the wellbore after the weight is disassociated from the body.

2. The method according to claim 1, wherein the device is a tool.

3. The method according to claim 1, wherein the device is an isolation device.

4. The method according to claim 1, wherein the device is an information communications device.

5. The method according to claim 4, wherein the information communication device communicates a command to a downhole tool.

6. The method according to claim 4, wherein the information communications device communicates information about a downhole parameter to the surface of the wellbore.

7. The method according to claim 6, wherein the information communications device further comprises one or more sensors located in the body of the device.

8. The method according to claim 6, wherein the information communications device further comprises a receiver for receiving information from one or more downhole sensors, wherein the receiver is located in the body of the device.

9. The method according to claim 1, wherein the body comprises a first material.

10. The method according to claim 9, wherein the first material is a solid.

11. The method according to claim 9, wherein the first material is a liquid, a gas, or combinations thereof, and wherein the body further comprises an enclosure for the first material.

12. The method according to claim 1, wherein the body has a specific gravity substantially similar to or less than the specific gravity of a fluid located in the wellbore.

13. The method according to claim 1, wherein the body has a specific gravity less than 1.1 at a temperature of 71° F. and a pressure of 1 atmosphere.

14. The method according to claim 1, wherein the body is connected to the weight during introduction of the device into the wellbore.

15. The method according to claim 1, wherein the substance the weight is made from has a specific gravity of at least 3 at a temperature of 71° F. and a pressure of 1 atmosphere.

16. The method according to claim 1, wherein the weight is made from a degradable substance.

17. The method according to claim 16, wherein the weight is directly connected to the body.

18. The method according to claim 1, wherein the weight is indirectly connected to the body via a tether or a connector, and wherein the weight is made from a non-degradable substance.

19. The method according to claim 18, wherein the tether or connector is made from a degradable substance.

20. A system for performing an operation in a wellbore using a device, the system comprising:

the device, wherein the device initially comprises a body and a weight; and

the wellbore;

wherein the device is located within the wellbore, wherein initially the body is directly or operatively connected to the weight, wherein the device comprises the body after the weight becomes disconnected from the body, and wherein the specific gravity of the device decreases after the weight becomes disconnected from the body.