Carrier Device for Downhole Transport

Abstract

Apparatus for transport in a wellbore, including a body comprising degradable material; a compartment within the body; and a permeable closure between an interior of the compartment and an exterior of the body. A method for transport in a wellbore including deploying a carrier device into a borehole of the wellbore, wherein the carrier device contains items; and releasing the items into the borehole by allowing degradation of at least a portion of the carrier device. A wellbore system including a borehole having an inner diameter; a carrier device having an outer diameter, wherein the inner diameter of the borehole is greater than the outer diameter of the carrier device, the carrier device comprising: a body comprising degradable material; a compartment within the body; and a permeable closure between an interior of the compartment and an exterior of the body.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application 62/754,010 filed Nov. 1, 2018 entitled Carrier Device for Downhole Transport, the entirety of which is incorporated by reference herein.

FIELD

This disclosure relates generally to the field of wellbore construction and/or operations to enable production of subsurface hydrocarbons. Specifically, exemplary embodiments relate to methods and apparatus for transporting items in a wellbore. Additionally, exemplary embodiments relate to methods and apparatus for transporting items without the use of a transport line.

BACKGROUND

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the surrounding formations.

It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. Thus, the process of drilling and then cementing progressively smaller strings of casing may be repeated multiple times. The final string of casing, referred to as a production casing, is cemented into place.

As part of the completion process, the production casing is perforated at a desired level, typically at a zone of interest in the subsurface formation. This means that lateral holes are shot through the casing and the cement sheath surrounding the casing. The perforations allow hydrocarbon fluids to flow into the wellbore.

Various techniques are known for running a bottom hole assembly (“BHA”) into a wellbore, and then creating fluid communication between the wellbore and various zones of interest. In most embodiments, the BHA includes various perforating guns having associated charges. In most embodiments, the BHA is deployed in the wellbore by means of a transport line (e.g., wireline) extending from the surface. The wireline provides electrical signals to the perforating guns for detonation. The electrical signals allow the operator to cause the charges to detonate, thereby forming perforations. Many of the various embodiments for a BHA include a means for deploying the assembly into the wellbore, and then translating the assembly up and down the wellbore. Such translation means include a string of coiled tubing, conventional jointed tubing, a wireline, an electric line, or a downhole tractor. Moreover, installation or deployment of downhole pressure temperature measuring systems typically requires use of a transport line, such as wireline or slickline.

Typically, a transport line runs over a pulley and then down through a lubricator. To protect the transport line from abrasive fracturing fluid, the wellhead may also include a transport line isolation tool. The transport line isolation tool provides a means to protect the transport line from the direct flow of proppant-laden fluid injected into side outlet injection valves.

The use of a crane and suspended lubricator add expense and complexity to a well completion operation, thereby lowering the overall economics of a well-drilling project. Further, cranes and transport line equipment present on location occupy needed space.

It would be beneficial to transport items downhole without using a transport line, wireline, slickline, lubricator, and/or and a crane arm. Further, it would be beneficial if such downhole transport mechanisms are autonomous, meaning that they are not necessarily controlled (e.g., mechanically and/or electrically) from the surface.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only exemplary embodiments and are therefore not to be considered limiting of its scope, may admit to other equally effective embodiments.

FIG. 1 illustrates a wellbore suitable for embodiments disclosed herein.

FIGS. 2A and 2B illustrate a carrier device for use in the wellbore of FIG. 1.

FIG. 3 illustrates another carrier device for use in the wellbore of FIG. 1.

DETAILED DESCRIPTION

It is to be understood that the present disclosure is not limited to particular devices or methods, which may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used herein, the singular forms “a,” “an,” and “the” include singular and plural referents unless the content clearly dictates otherwise. Furthermore, the words “can” and “may” are used throughout this application in a permissive sense (i.e., having the potential to, being able to), not in a mandatory sense (i.e., must). The term “include,” and derivations thereof, mean “including, but not limited to.” The term “coupled” means directly or indirectly connected. The word “exemplary” is used herein to mean “serving as an example, instance, or illustration.” Any aspect described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other aspects. The term “uniform” means substantially equal for each sub-element, within about ±10% variation.

As used herein, “hydrocarbon management” or “managing hydrocarbons” includes any one or more of the following: hydrocarbon extraction; hydrocarbon production, (e.g., drilling a well and prospecting for, and/or producing, hydrocarbons using the well; and/or, causing a well to be drilled to prospect for hydrocarbons); hydrocarbon exploration; identifying potential hydrocarbon-bearing formations; characterizing hydrocarbon-bearing formations; identifying well locations; determining well injection rates; determining well extraction rates; identifying reservoir connectivity; acquiring, disposing of, and/or abandoning hydrocarbon resources; reviewing prior hydrocarbon management decisions; and any other hydrocarbon-related acts or activities. The aforementioned broadly include not only the acts themselves (e.g., extraction, production, drilling a well, etc.), but also or instead the direction and/or causation of such acts (e.g., causing hydrocarbons to be extracted, causing hydrocarbons to be produced, causing a well to be drilled, causing the prospecting of hydrocarbons, etc.).

If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted for the purposes of understanding this disclosure.

One of the many potential advantages of the embodiments of the present disclosure is that items (e.g., downhole devices, sensors) may be transported to target depths (e.g., for measurement of pressures and/or temperatures at specific zones of interest) without necessarily requiring the use of a transport line (such as a slickline or a wireline). As such, embodiments of the present disclosure may save costs and/or installation time compared to transport line-based systems. Another potential advantage includes a degradable carrier device that will not obstruct the borehole during subsequent operations. Embodiments of the present disclosure can thereby be useful in the discovery and/or extraction of hydrocarbons from subsurface formations.

FIG. 1 presents a side view of a well site 100. The well site 100 includes a wellhead 170 and a wellbore 110. The wellbore 110 includes a borehole 115, extending from the surface 103 of the earth, and into the subsurface region 105. As illustrated, the wellbore 110 traverses at least zones of interest “T” and “U” within the subsurface region 105. Although illustrated essentially linearly and vertically, it should be understood that wellbore 110 may include various bends and/or be disposed at various orientations within the subsurface region 105. As such, terms such as “downhole” or “downward” should be understood to indicate wellbore locations or directions distal from wellhead 170, while terms such as “uphole” or “upward” should be understood to indicate wellbore locations or directions proximal to wellhead 170. It should be understood that the depth of the wellbore 110 may extend up to many thousands of feet below the surface 103. Typically, borehole 115 will contain, and/or be filled with, a variety of fluids, such as water, gas, oil, mud, production fluids, etc., generally referred to herein as wellbore fluids.

In some embodiments, the wellbore 110 includes one or more strings of casing (e.g., surface casing 120, production casing 130). The casing strings may be secured in the wellbore 110, for example with cement sheath 112 and/or cement sheath 114. As illustrated, the production casing 130 has a lower end proximate a bottom 134 of the wellbore 110. In some embodiments, borehole 115 may be uncased or partially cased. In some embodiments, production casing 130 may be perforated or otherwise configured to provide fluid contact between borehole 115 and subsurface region 105. As illustrated, the inner diameter of production casing 130 defines the width of borehole 115.

In some embodiments, wellhead 170 includes a variety of valves, pipes, tanks, fittings, couplings, gauges, and other devices (e.g., one or more valves 125). For example, valves 125 may be used to selectively seal the wellbore 110. The wellhead 170 and valves 125 may be used for flow control and/or hydraulic isolation during completion, rig-up, stimulation, rig-down, and/or shut-in operations. The wellhead 170 may be configured to allow tool strings and other downhole equipment to be run into and out of the wellbore 110 (e.g., using electric line, slick line, or coiled tubing). In some embodiments, wellhead 170 may be configured to allow deployable downhole equipment, such as plugs, balls, and/or carrier devices, to be deployed (e.g., dropped) into borehole 115 and/or retrieved therefrom.

FIG. 2A presents a cross-sectional view, and FIG. 2B presents a top view, of a carrier device 200 for deployment downhole in wellbore 110. Carrier device 200 includes a body 210 and a compartment 240 within the body 210. Compartment 240 may be configured to contain and/or retain items while carrier device 200 is deployed downhole. The outer dimensions of body 210 allow for passage of carrier device 200 through borehole 115. For example, the outer diameter of body 210 may be less than the width of borehole 115 (e.g., the inner diameter of production casing 130). As illustrated, body 210 is cylindrical, but other shapes may be considered, such as conical or spherical. Suitable shapes for body 210 allow passage through borehole 115 and any wellbore fluids contained therein. In some embodiments, the shape of body 210 is hydrodynamically favorable for downward travel in borehole 115.

In some embodiments, carrier device 200 includes one or more flow ports 220 through body 210. In some embodiments, a flow port 220 may include one or more valves 225. Flow ports 220 may have dimensions and orientations selected to allow fluid flow through body 210 as carrier device 200 travels through wellbore fluids in borehole 115. For example, as illustrated, a flow port 220 extends between a bottom portion 230 of carrier device 200 and a top portion thereof. As illustrated, valve 225 allows fluid flow from the bottom portion 230 of carrier device towards the top end thereof. In some embodiments, valve 225 may be a one-way valve. In some embodiments, valve 225 may allow fluid flow upwardly through body 210 as carrier device travels through wellbore fluids in borehole 115, but valve 225 may prevent fluid flow downwardly through body 210. In some embodiments, flow port 220 and valve 225 may assist carrier device 200 in traveling downwardly through wellbore fluids in borehole 115. In some embodiments, flow port 220 and valve 225 may resist carrier device 200 from traveling upwardly through wellbore fluids in borehole 115. For example, carrier device 200 may sink under the influence of gravity. As another example, carrier device 200 may travel downwardly due to pressure and/or pumping initiated at or near the surface 103 (e.g., by a pumping device attached to wellhead 170). As another example, carrier device 200 may remain at or near bottom 134 of wellbore 110 during production of fluids therefrom.

In some embodiments, carrier device 200 may include weights, fins, and/or hydrodynamic structures to orient body 210 in borehole 115. For example, bottom portion 230 of carrier device 200 may be weighted (relative to the remainder of carrier device 200 in a loaded configuration) to sink preferentially as body 210 passes through wellbore fluids in borehole 115. The thickness of body 210 at or near bottom portion 230 of carrier device 200 may be selected to provide appropriate weighting.

In some embodiments, carrier device 200 includes a fluid-permeable closure (e.g., permeable closure 250) between an interior of compartment 240 and an exterior of the body 210. Wellbore fluids present in borehole 115 may pass through permeable closure 250 to come into contact with the interior of compartment 240 (and any items contained therein). In some embodiments, permeable closure 250 may be a removable closure. In some embodiments, the permeable closure 250 may be configured to retain microsensors in compartment 240. For example, openings of the permeable closure 250 (between the interior of compartment 240 and the exterior of body 210) may be less than 3 mm across. In some embodiments, permeable closure 250 may be wire mesh. As illustrated, permeable closure 250 may be disposed at or near an exterior surface of body 210. In some embodiments, permeable closure 250 may be disposed within compartment 240 (e.g., in a “neck” of the compartment). Permeable closure 250 may be removed for loading items into compartment 240. Permeable closure 250 may then be secured to body 210 to encase such items in compartment 240. Permeable closure 250 may allow fluid communication between the environment surrounding carrier device 200 (e.g., any wellbore fluids) and compartment 240. Although illustrated at a top portion of carrier device 200, permeable closure 250 may be located anywhere on body 210. Although illustrated with a circular cross-sectional area, permeable closure 250 may have any of a variety of sizes and/or shapes. Although illustrated as a singular form covering a singular opening of carrier device 200, permeable closure 250 may include multiple forms covering multiple openings on body 210. It should be understood that passage of carrier device 200 through wellbore fluids may be impacted by the size, shape, number, and/or location of permeable closure(s) 250 on body 210. In some embodiments, permeable closure 250 may be made of degradable material. In some embodiments, permeable closure 250 may be buoyant in wellbore fluids. In some embodiments, permeable closure 250 may be configured to sink to the bottom 134 of wellbore 110 when disconnected from body 210.

Carrier device 200 may be configured to release items from compartment 240 into borehole 115. In some embodiments, carrier device 200 may be configured to release the items after a selected time period (e.g., days, weeks, months). For example, carrier device 200 may be deployed into borehole 115 at time t₀. Carrier device 200 may then travel downwardly through borehole 115. After a first time period, t₁ (e.g., several hours), carrier device 200 may reach a first zone of interest, such as Zone U in FIG. 1. In some embodiments, carrier device 200 may be configured to release the items after the first time period, and therefore the items would be released into borehole 115 at or near Zone U. Alternatively, in some embodiments, carrier device 200 may be configured to wait a second time period, t₁ (e.g., several days), before releasing the items. Therefore, carrier device 200 may travel downwardly through borehole 115 until at or near bottom 134. Carrier device 200 may then wait the remainder of the second time period and then release the items at or near the bottom 134 of wellbore 110.

In some embodiments, carrier device 200 may be configured to release the items after a triggering event. In some embodiments, carrier device 200 may be configured to release the items after a selected time period following a triggering event. In some embodiments, the release of the items by carrier device 200 may be triggered by depth, pressure, temperature, chemical means, electromagnetic means, mechanical means (e.g., erosion due to flow), or a combination thereof. In some embodiments, carrier device 200 may be configured to release the items at a target depth within wellbore 110 (e.g., at a zone of interest, such as Zone U or Zone T, or proximal the bottom 134 of wellbore 110).

In some embodiments, some portions of carrier device 200 may degrade at different rates or in response to different circumstances than other portions. For example, body 210 may be reinforced near or at flow port 220. Portions of body 210 near or at compartment 240 may degrade more quickly than portions of body 210 near or at flow port 220. This may have the effect of allowing carrier device 200 to sink through wellbore fluids even after degradation of portions of body 210 has released some of the items from compartment 240.

In some embodiments, carrier device 200 may be made of degradable materials. For example, body 210, permeable closure 250, and/or a connection between body 210 and permeable closure 250 may degrade in the presence of a wellbore fluid. In some embodiments, the materials used for body 210 and/or the dimensions of body 210 may be selected to degrade over a selected time period. For example, the material may include thermosetting adhesives and/or fillers that are soluble over a controlled period of time in one or more wellbore fluids, such as fresh water, salt water, brine, seawater, water-based drilling and completion fluids, or combination thereof, or non-aqueous based fluids such as diesel, crude oil, aromatic mineral oil, non-aromatic mineral oil, olefins, benzene, ether, ester, paraffins, or combinations thereof. In some embodiments, the presence of a particular fluid in wellbore 110 may trigger body 210 to degrade. In some embodiments, fluid properties (e.g., pressure, temperature, salinity, pH, or changes thereof) of a fluid within wellbore 110 may trigger body 210 to degrade. In some embodiments, the presence of a signal may trigger body 210 to degrade. For example, carrier device 200 may receive a signal from a downhole radio-frequency identification (RFID) tag to trigger degradation.

In some embodiments, carrier device 200 may open compartment 240 while within borehole 115, for example by releasing permeable closure 250. In some embodiments, the materials used for permeable closure 250, body 210, and/or any connections therebetween may be selected to dissolve, degrade, fracture, or release over a selected time period. In some embodiments, the presence of a particular fluid in wellbore 110 may trigger compartment 240 to open. In some embodiments, fluid properties (e.g., pressure, temperature, salinity, pH, or changes thereof) of a fluid within wellbore 110 may trigger compartment 240 to open. In some embodiments, carrier device 200 may receive a signal from a downhole RFID tag to trigger opening.

In some embodiments, the items contained by compartment 240 may include microsensors. For example, the microsensors may be between about 3 mm and about 12 mm in diameter. In some embodiments, compartment 240 may contain between about 50 and about 100 microsensors. The microsensors may be configured to detect and/or measure fluid properties (e.g., pressure, temperature, salinity, pH, etc.). In some embodiments, compartment 240 may contain a combination of various types of microsensors. The microsensors may be capable of recording one or more measurements. For example, the microsensors may measure and/or record properties of the fluid to which they are exposed while contained in compartment 240. The microsensors may be configured to move towards surface 103 once released from compartment 240. For example, the microsensors may be buoyant in typical wellbore fluids. As another example, the microsensors may be moved towards surface 103 during production of fluids from wellbore 110. Some or all of the microsensors may be collected from borehole 115 at or near wellhead 170 to retrieve recorded information from the measurements made downhole. The microsensors may be configured to wirelessly communicate with one another and/or other equipment. For example, wireless communication may be utilized to retrieve recorded information from the collected microsensors. As another example, a first microsensor may wirelessly communicate information that it previously detected and/or measured to a second microsensor. The second microsensor may record that information. Thus, if only the second microsensor is collected at the surface 103, the information from the first microsensor would still be available for retrieval.

In some embodiments, a microsensor may be encased in a degradable material. The degradable encasement may designed to degrade over a different time period than body 210. For example, carrier device 200 may travel downhole with encased microsensors in compartment 240. After a first time period, fluid passing through permeable closure 250 may degrade the encasements, and the microsensors may detect and/or measure properties of the fluid. After a second time period, body 210 may degrade, releasing the microsensors into borehole 115. The microsensors may then move towards surface 103 and be collected at or near wellhead 170. Information about the downhole fluid properties after the first time period may then be retrieved from the microsensors.

In some embodiments, the microsensors may detect, measure, and/or record information about wellbore fluid while carrier device 200 travels downwardly through borehole 115. In some embodiments, the microsensors may detect, measure, and/or record information about wellbore fluid while carrier device 200 is at or near the bottom 134 of wellbore 110 (prior to release from compartment 240). In some embodiments, wellbore 110 may be shut-in or otherwise not producing for some or all of the time period that the microsensors are retained in compartment 240. It should be appreciated that the hydrodynamically favorable shape of body 210 and/or the flow ports 220 may allow carrier device 200 to sink and/or remain at or below a selected depth in wellbore 110 even during production phases.

Body 210 may be constructed by a variety of techniques. For example, body 210 may be injection molded. As another example, body 210 may be constructed by additive manufacturing (e.g., 3D printing). As another example, body 210 may be carved or machined from a block of material. As another example, body 210 may be cast. In some embodiments, the items in compartment 240 may be encased in body 210 during the manufacturing process. In some embodiments, the items may be loaded into compartment 240 after body 210 has been manufactured.

FIG. 3 illustrates an optional fishing neck 360 for carrier device 200. Carrier device 200 may be configured to travel through borehole 115 without obstruction. Also, carrier device 200 may be configured to degrade to release items from compartment 240, thereby not subsequently obstructing borehole 115. Nonetheless, there may be circumstances when it would be beneficial to retrieve carrier device 200 from wellbore 110. Fishing neck 360 may be utilized to retrieve carrier device 200.

The above-described techniques, and/or systems implementing such techniques, can further include hydrocarbon management based at least in part upon the above techniques. For instance, methods according to various embodiments may include managing hydrocarbons based at least in part upon wellbore construction and/or operations according to the above-described methods.

The foregoing description is directed to particular example embodiments of the present technological advancement. It will be apparent, however, to one skilled in the art, that many modifications and variations to the embodiments described herein are possible. All such modifications and variations are intended to be within the scope of the present disclosure, as defined in the appended claims.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil and gas industries.

It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions, and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements, and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.

Claims

1. A carrier device for transport in a wellbore, comprising:

a body comprising degradable material;

a compartment within the body; and

a permeable closure between an interior of the compartment and an exterior of the body.

2. The carrier device of claim 1, wherein the body is cylindrical.

3. The carrier device of claim 1, wherein the body has a shape that is hydrodynamically favorable for downward travel in a borehole of the wellbore.

4. The carrier device of claim 1, wherein the permeable closure comprises a wire mesh.

5. The carrier device of claim 4, wherein the wire mesh consists of openings that are less than 3 mm across.

6. The carrier device of claim 1, wherein the permeable closure is disposed at an exterior surface of the body.

7. The carrier device of claim 1, wherein the permeable closure is located near a top portion of the body.

8. The carrier device of claim 1, further comprising a flow port extending between a bottom portion of the body and a top portion of the body.

9. The carrier device of claim 8, further comprising a valve in the flow port.

10. The carrier device of claim 9, wherein the valve allows fluid flow from the bottom portion of the body to the top portion of the body.

11. The carrier device of claim 8, wherein the body is reinforced near the flow port.

12. The carrier device of claim 1, wherein a bottom portion of the body is weighted.

13. The carrier device of claim 1, further comprising a fishing neck.

14. The carrier device of claim 1, wherein:

the wellbore comprises a borehole having an inner diameter; and

an outer diameter of the body is less than the inner diameter of the borehole.

15. The carrier device of claim 1, wherein the compartment is capable of retaining microsensors.

16. A method of transport in a wellbore, comprising:

deploying a carrier device into a borehole of the wellbore, wherein the carrier device contains items; and

releasing the items into the borehole by allowing degradation of at least a portion of the carrier device.

17. The method of claim 16, wherein wellbore fluid comes into contact with the items after the deploying and before the releasing.

18. The method of claim 16, further comprising: triggering the degradation of the carrier device.

19. The method of claim 18, wherein the triggering is based on at least one of fluid pressure, fluid pressure changes, fluid temperature, fluid temperature changes, fluid salinity, fluid salinity changes, fluid pH, and fluid pH changes.

20. The method of claim 16, wherein the portion of the carrier device that is degraded comprises at least one of a body of the carrier device, a permeable closure connected to the body, and a connection between the body and the permeable closure.

21. The method of claim 16, wherein the items are microsensors, the method further comprising collecting at least some of the microsensors from the borehole.

22. The method of claim 16, further comprising loading the items into a compartment of the carrier device before deploying the carrier device into the borehole.

23. The method of claim 22, wherein loading the items into the compartment occurs after manufacture of a body of the carrier device.

24. The method of claim 16, wherein the deploying the carrier device into the borehole is separated from the releasing the items into the borehole by a selected time period.

25. The method of claim 24, further comprising selecting a material for the carrier device so that the carrier device is expected to degrade over the selected time period.

26. A wellbore system comprising:

a borehole having an inner diameter;

a carrier device having an outer diameter, wherein the inner diameter of the borehole is greater than the outer diameter of the carrier device, the carrier device comprising: a body comprising degradable material; a compartment within the body; and a permeable closure between an interior of the compartment and an exterior of the body.

27. The wellbore system of claim 26, wherein the body has a shape that is hydrodynamically favorable for downward travel in the borehole.

28. The wellbore system of claim 26, wherein the compartment is capable of retaining microsensors.