DOWNHOLE CONSTRUCTION OF VACUUM INSULATED TUBING

Abstract

A method for adjusting a pressure within a wellbore. The method can include inserting a first tubing into the wellbore. The method can also include mechanically coupling a bottom coupling feature of a multiple connection bushing to the first tubing. The method can further include mechanically coupling a second tubing to a first top coupling feature of the multiple connection bushing. The method can also include mechanically coupling a third tubing to a second top coupling feature of the multiple connection bushing, where the third tubing has an inner diameter that is greater than an outer diameter of the second tubing. The method can further include inserting the multiple connection bushing, the second tubing and the third tubing into the wellbore. The method can also include adjusting the pressure within a space between the second tubing, the third tubing, and the multiple connection bushing.

Description

TECHNICAL FIELD

The present application relates to adjusting pressure within a wellbore, and in particular, methods and systems of adjusting pressure using tubing downhole in a subterranean wellbore.

BACKGROUND

Heavy oil and tar sands comprise significant existing resources for liquid hydrocarbons to the extent that they can be economically produced. Generally, heavy oil from tar sand and bitumen deposits must be heated to reduce the oil or mineral viscosity before it will flow, or to enhance flow, into producing wells. The predominant method for heating utilized in the field is the injection of a hot fluid or gas (generally referred to herein as a “working fluid”), usually steam, from the surface, although electrical heating is also practiced. However, as the working fluid passes through production tubing, heat is generally lost to the surrounding rock based on the thermal conductivity of the exterior of the production tubing system.

Generally, vacuum insulated tubing having a relatively low heat conductance value can be utilized as a thermal insulator for minimizing heat loss from the working fluid into the surrounding rock. Conventional vacuum insulated tubing is manufactured by incorporating a tubing sheath or segment on an exterior of a joint of tubing, welding at each end of the tubing near a connection to create a seal, and then drawing a vacuum between the two pipe segments. This conventional method of constructing vacuum-insulated tubing can be expensive, however, and does not provide insulation at the connection areas. Therefore, heat loss from the working fluid into the surrounding rock may be realized between each segment of the vacuum insulated tubing. If too much thermal energy is conducted from one side of the vacuum to the other through the poorly insulated connection areas, damage can occur to the formation.

SUMMARY

In general, in one aspect, the disclosure relates to a method for adjusting a pressure within a wellbore. The method can include inserting a first tubing into the wellbore, and mechanically coupling a bottom coupling feature of a multiple connection bushing to the first tubing, where the multiple connection bushing further includes a first top coupling feature and a second top coupling feature. The method can also include mechanically coupling a second tubing to the first top coupling feature of the multiple connection bushing, and mechanically coupling a third tubing to the second top coupling feature of the multiple connection bushing, where the third tubing has an inner diameter that is greater than an outer diameter of the second tubing. The method can further include inserting the multiple connection bushing, the second tubing, and the third tubing into the wellbore, and adjusting the pressure within a space between the second tubing, the third tubing, and the multiple connection bushing.

In general, in one aspect, the disclosure relates to a method for extracting a downhole fluid in a wellbore using vacuum-insulated tubing. The method can include inserting first tubing into the wellbore, and mechanically coupling a bottom coupling feature of a multiple connection bushing to the first tubing, where the multiple connection bushing further comprises a first top coupling feature and a second top coupling feature. The method can also include mechanically coupling a second tubing to the first top coupling feature of the multiple connection bushing, and mechanically coupling a third tubing to the second top coupling feature of the multiple connection bushing, where the third tubing has an inner diameter that is greater than an outer diameter of the second tubing. The method can further include inserting the multiple connection bushing, the second tubing, and the third tubing into the wellbore, and adjusting a pressure within a space between the second tubing, the third tubing, and the multiple connection bushing. The method can also include inserting a working fluid into a cavity formed by an annulus of the first tubing, a passage through the multiple connection bushing, and an annulus of the second tubing. The method can further include extracting, using completion equipment, production fluid after the working fluid interacts with the production fluid.

In another aspect, the disclosure can generally relate to a system for adjusting a pressure within a wellbore. The system can include a first tubing disposed within the casing and having an open distal end and a proximal end. The system can also include a multiple connection bushing mechanically coupled to the proximal end of the first tubing using a bottom coupling feature, where the multiple connection bushing further includes a first top coupling feature and a second top coupling feature. The system can further include a second tubing disposed within the casing and mechanically coupled to the first top coupling feature of the multiple connection bushing. The system can also include a third tubing disposed within the casing and mechanically coupled to the second top coupling feature of the multiple connection bushing, where the third tubing has an inner diameter that is greater than an outer diameter of the second tubing. The system can further include a vacuum system located proximate to a surface and communicably coupled to a space between the second tubing and the third tubing, where the vacuum system adjusts the pressure within the space.

These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings illustrate only example embodiments of methods, systems, and devices for creating vacuum-insulated tubing in a wellbore (also called herein a “borehole”) and are therefore not to be considered limiting of its scope, as creating vacuum-insulated tubing in a wellbore may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positionings may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements. Designations such as “first”, “second”, and “third” are merely used to show a different feature. Descriptions such as “top”, “bottom”, “distal”, and “proximal” are meant to describe different portions of an element or component and are not meant to imply an absolute orientation.

FIG. 1 shows a schematic diagram of a field system in which vacuum-insulated tubing can be created in a wellbore in accordance with certain example embodiments.

FIG. 2 shows a schematic diagram of a system for adjusting a pressure within a wellbore in accordance with certain example embodiments.

FIG. 3 shows a schematic diagram of another system for adjusting a pressure within a wellbore in accordance with certain example embodiments.

FIG. 4 shows a flowchart presenting a method for adjusting a pressure within a wellbore in accordance with certain example embodiments.

FIG. 5 shows a flowchart presenting a method for extracting a downhole fluid in a wellbore using vacuum-insulated tubing in accordance with certain example embodiments.

DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS

Example embodiments directed to vacuum-insulated tubing in a wellbore will now be described in detail with reference to the accompanying figures. Like, but not necessarily the same or identical, elements in the various figures are denoted by like reference numerals for consistency. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure herein. However, it will be apparent to one of ordinary skill in the art that the example embodiments herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. As used herein, a length, a width, and a height can each generally be described as lateral directions.

In certain example embodiments, production fluid as described herein is one or more of any solid, liquid, and/or vapor that can be found in a subterranean formation. Examples of a production fluid can include, but are not limited to, crude oil, natural gas, water, steam, and hydrogen gas. Production fluid can be called other names, including but not limited to downhole fluid, reservoir fluid, a resource, and a field resource.

A user as described herein may be any person that is involved with extracting and/or controlling one or more production fluids in a wellbore of a subterranean formation of a field. Examples of a user may include, but are not limited to, a company representative, a drilling engineer, a tool pusher, a service hand, a field engineer, an electrician, a mechanic, an operator, a consultant, a contractor, a roughneck, and a manufacturer's representative.

As used herein a working fluid can be used to describe any liquid or vapor that has a temperature that is higher (in some cases, significantly higher) than the temperature of a production fluid in a wellbore. The working fluid can be sent into the wellbore and transfer heat to the production fluid in the wellbore. By heating the production fluid, the production fluid can be extracted from the wellbore more easily because the viscosity increases. An example of a working fluid is high-temperature steam.

FIG. 1 shows a schematic diagram of a field system 100 in which vacuum-insulated tubing can be created and used in a subterranean wellbore in accordance with one or more example embodiments. In one or more embodiments, one or more of the features shown in FIG. 1 may be omitted, added, repeated, and/or substituted. Accordingly, embodiments of a field system should not be considered limited to the specific arrangements of components shown in FIG. 1.

Referring now to FIG. 1, the field system 100 in this example includes a wellbore 120 that is formed in a subterranean formation 110 using field equipment 130 above a surface 102, such as ground level for an on-shore application and the sea floor for an off-shore application. The point where the wellbore 120 begins at the surface 102 can be called the entry point. The subterranean formation 110 can include one or more of a number of formation types, including but not limited to shale, limestone, sandstone, clay, sand, and salt. In certain embodiments, a subterranean formation 110 can also include one or more reservoirs in which one or more resources (e.g., oil, gas, water, steam) can be located. One or more of a number of field operations (e.g., drilling, setting casing, extracting production fluids) can be performed to reach an objective of a user with respect to the subterranean formation 110.

The wellbore 120 can have one or more of a number of segments, where each segment can have one or more of a number of dimensions. Examples of such dimensions can include, but are not limited to, a size (e.g., diameter) of the wellbore 120, a curvature of the wellbore 120, a total vertical depth of the wellbore 120, a measured depth of the wellbore 120, and a horizontal displacement of the wellbore 120. The field equipment 130 can be used to create and/or develop (e.g., create a vacuum within, insert a working fluid into, extract production fluids from) the wellbore 120. The field equipment 130 can be positioned and/or assembled at the surface 102. The field equipment 130 can include, but is not limited to, a derrick, a tool pusher, a clamp, a tong, drill pipe, a drill bit, a vacuum system, an injection device, completion equipment, a riser housing, a riser joint, centralizers, tubing pipe (also simply called tubing), a power source, a packer, and casing pipe (also simply called casing).

The field equipment 130 can also include one or more devices that measure and/or control various aspects (e.g., direction of wellbore 120, pressure, temperature) of a field operation associated with the wellbore 120. For example, the field equipment 130 can include a wireline tool that is run through the wellbore 120 to provide detailed information (e.g., curvature, azimuth, inclination) throughout the wellbore 120. Such information can be used for one or more of a number of purposes. For example, such information can dictate the size (e.g., outer diameter) of a casing pipe to be inserted at a certain depth in the wellbore 120.

FIG. 2 shows a schematic diagram of a system 200 for vacuum-insulated tubing in a wellbore in accordance with certain example embodiments. In one or more embodiments, one or more of the features shown in FIG. 2 may be omitted, added, repeated, and/or substituted. Accordingly, embodiments of a system for vacuum-insulated tubing should not be considered limited to the specific arrangements of components shown in FIG. 2.

The system 200 of FIG. 2 can include casing 260, a number of different tubing (e.g., tubing 210, tubing 215, tubing 220), a multiple connection bushing 230, a number of centralizers 250, a number of wellhead spools (e.g., lower wellhead spool 270, spacer wellhead spool 280, upper wellhead spool 290), a Christmas tree 295, a vacuum system 285, an injection device 207, a power source 203, completion equipment 297, and one or more power cables 299. Referring to FIGS. 1 and 2, the casing 260 can include a number of casing pipes that are mechanically coupled to each other end-to-end, usually with mating threads. The casing pipes of the casing 260 can be mechanically coupled to each other directly or using a coupling device, such as a coupling sleeve.

Each casing pipe of the casing 260 can have a length and a width (e.g., outer diameter). The length of a casing pipe can vary. For example, a common length of a casing pipe is approximately 40 feet. The length of a casing pipe can be longer (e.g., 60 feet) or shorter (e.g., 10 feet) than 40 feet. The width of a casing pipe can also vary and can depend on the cross-sectional shape of the casing pipe. For example, when the cross-sectional shape of the casing pipe is circular, the width can refer to an outer diameter, an inner diameter, or some other form of measurement of the casing pipe. Examples of a width in terms of an outer diameter can include, but are not limited to, 7 inches, 7⅝ inches, 8⅝ inches, 10¾ inches, 13⅜ inches, and 14 inches.

The size (e.g., width, length) of the casing 260 is determined based on the information gathered using field equipment 130 with respect to the wellbore 120 in the subterranean formation 110. The walls of the casing 260 have an inner surface that forms a cavity 208 that traverses the length of the casing 260. The casing 260 can be made of one or more of a number of suitable materials, including but not limited to steel. In certain example embodiments, the casing 260 is set along substantially all of the length of the wellbore 120. In order to extract production fluid from the reservoir in the formation 110, one or more of a number of perforations can be made in the casing 260. Such perforations allow the production fluid to enter the cavity 208 from a reservoir in the formation 110 adjacent to the perforations. The perforations can be made using one or more of a number of perforating technologies currently used or to be discovered with respect to a field operation.

The tubing (e.g., tubing 210, tubing 215, tubing 220) (sometimes called a tubing string) can include a number of tubing pipes (also called tubing pipe members) that are mechanically coupled to each other end-to-end, usually with mating threads. The tubing pipes of a tubing string can be mechanically coupled to each other directly or using a coupling device, such as a coupling sleeve. As in this case, more than one tubing string can be disposed within a cavity 208 of the casing 260.

Each tubing pipe of a tubing string can have a length and a width (e.g., outer diameter). The length of a tubing pipe can vary. For example, a common length of a tubing pipe is approximately 30 feet. The length of a tubing pipe can be longer (e.g., 40 feet) or shorter (e.g., 10 feet) than 30 feet. The width of a tubing pipe can also vary and can depend on one or more of a number of factors, including but not limited to the inner diameter of the casing pipe. For example, the width of the tubing pipe is less than the inner diameter of the casing pipe. The width of a tubing pipe can refer to an outer diameter, an inner diameter, or some other form of measurement of the tubing pipe. Examples of a width in terms of an outer diameter can include, but are not limited to, 7 inches, 5 inches, and 4 inches.

The distal end of the tubing 215 can be located toward the bottom of the wellbore 120, and the proximal end of the tubing 215 can be located closer to the surface 102. In certain example embodiments, the distal end of the tubing 215 is open (substantially unobstructed) and is positioned within the cavity 208 of the wellbore 120. In such a case, the casing 260 can extend further into the wellbore 120 than the tubing (in this case, tubing 215).

The size (e.g., outer diameter, length) of the tubing can be determined based, in part, on the size of the cavity 208 within the casing 260 and/or the configuration of the multiple connection bushing 230. The walls of the tubing have an inner surface that each forms a cavity. For example, the inner surface 212 of tubing 210 forms a cavity 216 (also called an annulus 216) that traverses the length of the tubing 210, and the inner surface of tubing 215 forms a cavity 217 (also called an annulus 217) that traverses the length of the tubing 215. The tubing can be made of one or more of a number of suitable materials, including but not limited to steel. The one or more materials of the tubing can be the same or different than the materials of the casing 260.

In certain example embodiments, the size of the tubing 220 is larger than the size of the tubing 210. For example, the tubing 220 can have an inner diameter (defined by inner surface 222) that is larger than the outer diameter (defined by outer surface 214) of the tubing 210. As a specific example, the tubing 210 can have an inner diameter of 3.5 inches and an outer diameter of 3.961 inches, while the tubing 220 can have an inner diameter of 4.611 inches and an outer diameter of 5.5 inches. In such a case, when the tubing 210 is positioned inside of the tubing 220, a space 240 is formed between the outer surface 214 of the tubing 210 and the inner surface 222 of the tubing 220. The size (e.g., inner diameter, outer diameter) of the tubing 210 can be substantially the same as, or different than, the size of the tubing 215.

The multiple connection bushing 230 is a device that has a number (e.g., three) of coupling features that allow the multiple connection bushing 230 to mechanically couple to multiple sizes of tubing (e.g., tubing 210, tubing 215, tubing 220) at one time. For example, the multiple connection bushing 230 can include a bottom coupling feature 233 that mechanically couples to the proximal end of the tubing 215. As another example, the multiple connection bushing 230 can include a top coupling feature 231 that mechanically couples to the distal end of the tubing 210. As still another example, the multiple connection bushing 230 can include another top coupling feature 232 that mechanically couples to the distal end of the tubing 220.

Each coupling feature of the multiple connection bushing 230 can be any type of coupling feature that complements the coupling feature of the respective tubing to which the multiple connection bushing 230 attaches. Examples of such coupling features can include, but are not limited to, mating threads, slots, and compression fittings. The multiple connection bushing 230 can include an inner surface 234 and an outer surface 236 and have a generally cylindrical shape. The inner surface 234 can form a passage 218 that traverses the length of the multiple connection bushing 230. The multiple connection bushing 230 can be made of one or more of a number of suitable materials, including but not limited to steel. In such a case, when a tubing is mechanically coupled to the multiple connection bushing 230, the tubing and the multiple connection bushing 230 form a tight seal that is substantially impervious to the passage of fluids or gases.

In certain example embodiments, one or more of a number of centralizers 250 are disposed between the tubing 210 and the tubing 220. Each centralizer 250 can be tubular in shape (wrapping around tubing 210), segmented, or have any of a number of other shapes and/or configurations. Each centralizer 250 can have one or more features (e.g., slots that traverse its height, a lattice structure) that allow air to flow therethrough. As such, when a centralizer is positioned in the space 240 between the tubing 210 and the tubing 220, there is no pressure differential between one side of the centralizer 250 and the other side of the centralizer 250.

The centralizer can be made of one or more of a number of thermally non-conductive materials, including but not limited to ceramic, plastic, and rubber. In certain example embodiments, each centralizer 250 is used to provide physical separation between the tubing 210 and the tubing 220. The centralizer 250 can be rigid or somewhat elastic. The width of a centralizer 250 can be substantially the same as, or less than, the width (e.g., one inch, one-half inch) of the space 240 between the tubing 210 and the tubing 220.

The space 240, formed between the tubing 210, the tubing 220, and the multiple connection bushing 250, is enclosed at or near the surface 102 by the spacer wellhead spool 280 and the vacuum system 285. The spacer wellhead spool 280 (also called a spacer wellhead bowl 280) is used to secure (in this case, seal) the upper end of the space between the tubing 210 and the tubing 220. The size and pressure rating of the spacer wellhead spool 280 can vary based on one or more of a number of factors, including but not limited to the size of the tubing 210, the size of the tubing 220, and the minimum and/or maximum pressure in the space 240 created by the vacuum system 285.

The vacuum system 285 can include one or more components that are used to adjust a pressure within the space 240. For example, as shown in FIG. 2, the vacuum system 285 can include a vacuum pump 283, piping 282, and an access valve 284, all of which can be used to create a vacuum in the space 240 by reducing the pressure in the space 240 toward zero (e.g., zero Torr). In addition, or in the alternative, the vacuum system 285 can act in reverse and increase the pressure within the space 240. In this case, the access valve 284 is mechanically coupled to the spacer wellhead spool 280 and provides access to the space 240 by the rest of the vacuum system 285. In other words, the access valve 284 allows the vacuum system 285 to be communicably coupled to the space 240.

The vacuum system 285 can be fixedly or removably coupled to the access valve 284. If some or all of the vacuum system 285 is removably coupled to the access valve 284, the access valve 284 can substantially maintain the pressure (or lack thereof) in the space 240 for a period of time (e.g., days, months) after such components of the vacuum system 285 are removed and no longer coupled to the access valve 284. The vacuum pump 283 can include a motor, a pump, and/or any other equipment to enable the vacuum pump 283 to create a vacuum in the space 240. The vacuum pump 283 and the piping 282 can be sized and/or configured in a manner consistent with the operating parameters of the system 200.

In certain example embodiments, one or more components (e.g., a motor, a motorized valve) of the vacuum system 285 can operate using electricity. Such components of the vacuum system 285 can run, at least in part, using electric power fed from, for example, one or more cables 299. For example, the power source 203 can be electrically coupled to the vacuum system 285 using the cable 299. The power source 203 can deliver a constant or a variable amount of power to the vacuum system 285.

In addition, or in the alternative, the power cables 299 can provide power generated by the power source 203 to one or more other components of the system 200. The power source 203 can be any device (e.g., generator, battery) capable of generating electric power. Other components of the system 200 that can operate using electric power generated by the power source 203 can include, but are limited to, completion equipment 297 and an injection device 207, each described below. In certain example embodiments, the power source 203 is electrically coupled to one or more cables 299. In such a case, the cables 299 can be capable of maintaining an electrical connection between the power source 203 and one or more components of the system 200 when such components are operating.

The power generated by the power source 203 can be alternating current (AC) power or direct current (DC) power. If the power generated by the power source 203 is AC power, the power can be delivered in a single phase. The power generated by the power source 203 can be conditioned (e.g., transformed, inverted, converted) by a power conditioner (not shown) before being delivered to the component using a cable 299.

In certain example embodiments, completion equipment 297 can be disposed within the cavity 208. In some cases, the completion equipment 297 is located below the first tubing 215 in the wellbore 120. The completion equipment 297 of FIG. 2 can include one or more of a number of components, including but not limited to a power conditioner, a motor, a pump, and a valve. For example, the completion equipment 297 can be a pump assembly (e.g., pump, pump motor) that can pump, when operating, oil, gas, and/or other production fluids from the wellbore 120 through the distal end of the tubing 215 and up the annulus 217 of the tubing 215, through the passage 218 of the multiple connection bushing, and up the annulus 216 of the tubing 210 to the surface 102.

One or more components of the completion equipment 297 can operate using electric power. In such a case, the completion equipment 297 can receive power from the power source 203 using a cable 299 that is run in the cavity 208 between the casing 260 and the outer surface 224 of the tubing 220. The power received by the completion equipment 297 can be the same type of power (e.g., AC power, DC power) generated by the power source 203. The power received by the completion equipment 297 can be conditioned (e.g., transformed, inverted, converted) into any level and/or form required by the completion equipment 297. In some cases, the completion equipment 297 can include a control system that controls the functionality of the completion equipment 297. Such a control system can be communicably coupled with a user and/or some other system so that the control system can receive and/or send commands and/or data.

In certain example embodiments, the cavity 208 is physically and/or thermally separated from the area in the wellbore 120 where the perforations are located so that the cavity 208 does not experience the same operating conditions as the area where the perforations are located. For example, one or more packers (not shown) can be installed (for example, between the tubing 215 and the casing 260 and/or wall of the wellbore 120. In such a case, the packers can have passages that traverse therethrough and allow one or more devices such as cables 299 to traverse the packers. In the case of cables 299, the cables 299 can traverse the packers to electrically couple to the completion equipment 297 located toward the bottom of the wellbore 120 (or, at least, below the packers).

In certain example embodiments, the lower wellhead spool 270 (also called the lower wellhead bowl 270) and the upper wellhead spool 290 (also called the upper wellhead bowl 290) are similar to the spacer wellhead spool 280. In this case, the lower wellhead spool 270 can be used to secure the upper end of the casing 260 and/or the tubing 220. In addition, the upper wellhead spool 290 can be used to secure the upper end of the tubing 210. The size and pressure rating of the lower wellhead spool 270 and the upper wellhead spool 290 can vary based one or more of a number of factors, including but not limited to the weight of the tubing 210, the weight of the tubing 220, and the weight of the casing 260.

The optional Christmas tree 295 is an assembly of devices such as valves, spools, pressure gauges, and chokes that are fitted to the wellhead and are used to control extraction of the production fluid. The Christmas tree 295 can be located at or near the surface 102. The Christmas tree 295 can include, or be separate from, the injection device 207. If one or more devices of the Christmas tree 295 require electrical power to operate, then the power source 203 can be electrically coupled to the Christmas tree 295.

The injection device 207 can be separate from or part of the Christmas tree 295 and can be used to send the working fluid into the wellbore through the cavity formed by the annulus 216 of the tubing 210, the passage 218 through the multiple connection bushing 230, and the annulus 218 of the tubing 215. The injection device 207 can be located at or near the surface 102. The injection device 207 can be communicably coupled to the cavity formed by the annulus 216 of the tubing 210, the passage 218 through the multiple connection bushing 230, and the annulus 217 of the tubing 215.

In certain example embodiments, the injection device 207 can also process (e.g., pressurize, heat) the working fluid before the working fluid is injected into the wellbore 120. The processing and injection of the working fluid can occur using the same or different devices. To the extent that one or more components of the injection device 207 requires electrical power to operate, then the power source 203 can be electrically coupled to the injection device 207 using one or more cables 299.

FIG. 3 shows a schematic diagram of another system 300 for vacuum-insulated tubing in a wellbore in accordance with certain example embodiments. In one or more embodiments, one or more of the features shown in FIG. 3 may be omitted, added, repeated, and/or substituted. Accordingly, embodiments of a system for vacuum-insulated tubing in a wellbore should not be considered limited to the specific arrangements of components shown in FIG. 3.

The components of the system 300 of FIG. 3 are substantially the same as the components of the system 200 of FIG. 2, as described above, with the exceptions noted below. For example, the lower wellhead spool 370, the tubing 310, the tubing 320, the casing 360, the vacuum system 385, and the spacer wellhead spool 380 of FIG. 3 are substantially the same as the lower wellhead spool 270, the tubing 210, the tubing 220, the casing 260, the vacuum system 285, and the spacer wellhead spool 280 of FIG. 2. FIG. 3 includes a casing wellhead spool 365, which can be used to secure the upper end of the casing 360 while the lower wellhead spool 370 can be used to secure the upper end of the tubing 220.

In place of the upper wellhead spool 290 shown in FIG. 2, FIG. 3 includes a riser 305 that includes a riser housing 308 and a riser joint 375. The riser housing 308 can be positioned atop the spacer wellhead spool 380 above the surface 102. The riser housing 308 can include a cavity 307 that is filled with a lubricant 387 (e.g., oil, grease). The riser housing 308 can also include at least one sealing member that keeps most of the lubricant 387 in the cavity 307 as the riser joint 375 moves up and down within a channel (hidden from view by the riser joint 375) that traverses the riser housing 308. In this example, a sealing member 304 is disposed within the top wall of the riser housing 308 and is located between the riser housing 308 and the riser joint 375. In addition, as shown in FIG. 3, a sealing member 303 is disposed within the bottom wall of the riser housing 308 and is located between the riser housing 308 and the riser joint 375.

In certain example embodiments, the riser joint 375 is mechanically coupled to the proximal end of the tubing 310. Since the riser joint 375 is able to move up and down within the channel that traverses the riser housing 308, the tubing 310 can freely expand and contract as its temperature rises and falls, coinciding with when the working fluid is injected into the wellbore 120 and when the production fluid is extracted from the wellbore 120.

The vacuum created in the space 340 acts as a tremendous insulator. Thus, the vacuum created in the space 340 can cause significant temperature differences between the tubing 310 and the tubing 320 as the working fluid is injected into the wellbore 120 through the cavity formed, in part, by the annulus of the tubing 310. For example, as working fluid is injected into the wellbore 120, the temperature of the tubing 310 can be approximately 750° F., while the temperature of the tubing 320 can be approximately 150° F. In such a case, the temperature of the working fluid can exceed 750° F.

As a result of the temperature differences between the tubing 310 and the tubing 320, the higher temperature tubing 310 can expand more than the relatively lower temperature tubing 320. The relative expansion of the tubing 310 compared to the tubing 320 can depend on one or more of a number of factors, including but not limited to the temperature of the working fluid, the depth of the wellbore 120, and the material used for the tubing 310 and the tubing 320. In a number of cases, as an example, the thermal expansion of the tubing 310 can be over 25 feet, while the thermal expansion of the tubing 320 can be only a couple of feet.

The riser 305 allows for this differential in expansion between the tubing 310 and the tubing 320. Specifically, as the tubing 310 expands at a faster rate than the tubing 320, the riser joint 375 elevates without compromising the vacuum formed in the space 340 between the tubing 310 and the tubing 320. Thus, the tubing 310 can receive uniform thermal distribution and so have more efficient transfer of the heat to the production fluid in the wellbore 120. The riser 305 also allows for a higher temperature differential between the tubing 310 and the tubing 320 without deforming or destroying a spool, compromising the vacuum, and/or causing any other problems in the system 300.

FIG. 4 is a flowchart presenting a method 400 for creating vacuum-insulated tubing in a wellbore in accordance with certain example embodiments. FIG. 5 is a flowchart presenting a method for extracting a downhole fluid in a wellbore using vacuum-insulated tubing in accordance with certain example embodiments. While the various steps in these flowcharts are presented and described sequentially, one of ordinary skill will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Further, in one or more of the example embodiments, one or more of the steps described below may be omitted, repeated, and/or performed in a different order. In addition, a person of ordinary skill in the art will appreciate that additional steps not shown in FIGS. 4 and 5, may be included in performing this method. Accordingly, the specific arrangement of steps should not be construed as limiting the scope.

Referring now to FIGS. 1, 2, 3, and 4, the example method 400 begins at the START step and proceeds to step 402, where tubing 215 is inserted into the wellbore 120. In certain example embodiments, the tubing 215 is a number of tubing members (or tubing pipes or tubing pipe members) that are mechanically coupled to each other on an end-to-end basis. The amount of tubing 215 that is inserted into the wellbore 120 can depend on one or more of a number of factors, including but not limited to the size of the reservoir, the inclination of the wellbore 120, and the size of the wellbore where the reservoir is located in the wellbore 120. The tubing 215 can be inserted into the wellbore 120 using field equipment 130, such as, for example, a top drive and a rotary table.

In step 404, a bottom coupling feature 233 of a multiple connection bushing 230 is mechanically coupled to the tubing 215. In certain example embodiments, the bottom coupling feature 233 of the multiple connection bushing 230 is mechanically coupled to the tubing 215 using field equipment 130, such as, for example, tongs, a clamping device, and a rotary table. The bottom coupling feature 233 of the multiple connection bushing 230 can be mechanically coupled to the tubing 215 at or above the surface 102.

In step 406, tubing 210 is mechanically coupled to a first top coupling feature 231 of the multiple connection bushing 230. In certain example embodiments, the tubing 210 is mechanically coupled to the first top coupling feature 231 of the multiple connection bushing 230 using field equipment 130, such as, for example, tongs, a clamping device, and a rotary table. The tubing 210 can be mechanically coupled to the first top coupling feature 231 of the multiple connection bushing 230 at or above the surface 102. In certain example embodiments, the tubing 210 is a number of tubing members that are mechanically coupled to each other on an end-to-end basis.

In step 408, tubing 220 is mechanically coupled to a second top coupling feature 232 of the multiple connection bushing 230. In certain example embodiments, the tubing 220 is mechanically coupled to the second top coupling feature 232 of the multiple connection bushing 230 using field equipment 130, such as, for example, tongs, a clamping device, and a rotary table. The tubing 220 can be mechanically coupled to the second top coupling feature 232 of the multiple connection bushing 230 at or above the surface 102. In some cases, after performing step 406, but prior to or while performing step 408, one or more centralizers 250 are positioned around an outer surface of the tubing 210.

In certain example embodiments, the tubing 220 has an inner diameter that is greater than an outer diameter of the tubing 210. In addition, or in the alternative, the tubing 220 can have an outer diameter that is less than an inner diameter of production tubing 260 inserted into the wellbore 120. In certain example embodiments, the tubing 220 is a number of tubing members that are mechanically coupled to each other on an end-to-end basis. The length of each tubing member of the tubing 220 can be the same or a different length of each tubing member of the tubing 210. When the tubing 210 and the tubing 220 are each a number of tubing members, the length of each of the tubing members can be the same or different than each other.

In step 410, the multiple connection bushing 230, the tubing 210, and the tubing 220 are inserted into the wellbore 120. The multiple connection bushing 230, the tubing 210, and the tubing 220 can be inserted into the wellbore 120 using field equipment 130, such as, for example, a top drive and a rotary table. When the tubing 210 and the tubing 220 are each a number of tubing members, one tubing member or a stand (e.g., three pre-connected) of tubing members of tubing 210 and tubing 220 can be mechanically coupled to the multiple connection bushing 230 before the multiple connection bushing 230, the tubing 210, and the tubing 220 are inserted into the wellbore 120. Subsequently, one or more additional tubing members or stands of tubing members of tubing 210 and tubing 220 can be mechanically coupled to the previously coupled portions of the tubing 210 and the tubing 220 that have been, at least partially, inserted into the wellbore 120.

In step 412, pressure is adjusted within the space 240 between the multiple connection bushing 230, the tubing 210, and the tubing 220. In certain example embodiments, the pressure within the space 240 is adjusted using a vacuum system 285 that is communicably coupled to a spacer wellhead spool 280. In such a case, the vacuum system 385 adjusts the pressure in the space 240 by removing pressure from the space 240. One or more components of the vacuum system 285 (e.g., the vacuum pump 283) can operate on electric power generated by a power source 203 that is electrically coupled to the vacuum system 285 using one or more cables 299. Alternatively, the vacuum system 385 can include one or more components (e.g., an air compressor) that allow the vacuum system 385 to adjust the pressure in the space 240 by increasing the pressure within the space 240. Once step 412 is completed, the process ends with the END step.

As discussed above with respect to FIG. 3, as a result of the vacuum created in the space 340 between the tubing 310 and the tubing 320, the tubing 310 can be subject to significantly higher temperatures than the tubing 320. Thus, in certain example embodiments, the tubing 310 can be allowed to expand and contract with temperature independent of the expansion and contraction of the tubing 320. Allowing the independent expansion and contraction of the tubing 310 relative to the tubing 320 can be achieved using, for example, the riser 305 that includes the riser housing 308 and the riser joint 375, where the riser joint is mechanically coupled to the top end of the tubing 310. In such a case, the space 340 can remain depressurized (or, in the alternative, pressurized) when the tubing 310 expands and contracts.

In addition to higher temperatures, the tubing 210 can also be subject to higher pressures than the tubing 220. Such pressures in the annulus 216 of the tubing 210 can be based on the injection pressure of the working fluid. For example, when the working fluid is injected through the annulus 216 of the tubing 210, the annulus 216 can be subjected to any of a number (e.g., 3,300 psi) of constant or variable pressures that substantially equal the injection pressure, as created by the injection device 207, of the working fluid. The amount of pressure in the annulus 216 of the tubing 210(and so also the injection pressure) can be controlled through the injection device 207 by a user, by an automated control system, and/or by some other means. In addition, the pressure within the space 340 can be substantially uniformly along its length. As a result, the temperature of the tubing 320 can be substantially equal along its length and substantially lower than the temperature of the tubing 310, which greatly reduces the risk of damaging the casing 360 and/or the wellbore 120.

By performing the method 400 of FIG. 4, the vacuum-insulated tubing in the wellbore 120 can be used in one or more of a number of applications that requires isolating temperatures and/or creating a radial and/or horizontal temperature differential within a wellbore 120. One such application is described below in FIG. 5, which shows a flowchart presenting a method 500 for extracting a downhole fluid in a wellbore using vacuum-insulated tubing in accordance with certain example embodiments. Those skilled in the art will appreciate that other applications associated with a field operation can be enhanced and/or performed using example vacuum-insulated tubing. Referring now to FIGS. 1, 2, 3, 4, and 5, the example method 500 begins at the START step and proceeds to step 502. Steps 502-512 of the method 500 of FIG. 5 are substantially similar to steps 402-412 of the method 400 of FIG. 5.

Once step 512 is complete, the method 500 continues to step 514, where a working fluid is inserted into the cavity formed by the annulus 216 of the tubing 210, the passage 218 through the multiple connection bushing 230, and the annulus 217 of the tubing 215. In certain example embodiments, the working fluid is inserted into the cavity by the injection device 207. The injection device 207 can inject a fixed or variable amount of working fluid that is regulated at a fixed or variable temperature. The injection device 207 can be controlled by a user, by a control system, and/or by some other means. In certain example embodiments, the temperature of the working fluid exceeds 750° F.

In step 516, production fluid is extracted from the wellbore 120 after the working fluid interacts with the production fluid in the wellbore 120. In certain example embodiments, the production fluid is extracted using completion equipment 297. As explained above, the tubing 210 can have a temperature that is substantially higher than the temperature of the tubing 220 when the working fluid is inserted into the cavity (and, more specifically, into the annulus 216 of the tubing 210). Once step 516 is completed, the process ends with the END step. Alternatively, when step 516 is completed, the method 500 can repeat one or more times by reverting to step 514.

The systems, methods, and apparatuses described herein allow for creating a vacuum (or adding pressure) within a portion of a wellbore using existing tubing. Example embodiments significantly reduce cost over currently used systems that include specially-made vacuum tubing. Further, example embodiments provide a vacuum that is continuous, rather than segmented when using currently available technology. As a result, the temperature of the components (e.g., casing) close to the wall of the wellbore (away from the radial center of the wellbore) are lower using example embodiments compared to using existing technology. Thus, there is a lower likelihood that high temperatures will compromise the wellbore where the working fluid passes.

In addition, using example embodiments, the inner-most tubing (i.e., the tubing through which the high-temperature working fluid is injected) can freely expand and contract, independent of the expansion and contraction of the outer tubing through which the inner-most tubing traverses. As a result, the working fluid can be injected into the wellbore at higher temperatures using example embodiments than it can using current technology. Thus, the viscosity of the production fluid can be further enhanced using example embodiments, making extraction of the production fluid easier and more cost-effective.

In addition to heating production fluid, the systems and methods described herein can be used in a number of other downhole applications. Specifically, the higher range of temperatures of the working fluid, the contiguousness of the vacuum, and/or the independent movement of the various components of the system can be used for one or more of a number of downhole applications within a wellbore. For example, systems and methods described herein can be used to cause a chemical reaction.

Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope and spirit of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein.

Claims

1. A method for adjusting a pressure within a wellbore, the method comprising:

inserting a first tubing into the wellbore;

mechanically coupling a bottom coupling feature of a multiple connection bushing to the first tubing, wherein the multiple connection bushing further comprises a first top coupling feature and a second top coupling feature;

mechanically coupling a second tubing to the first top coupling feature of the multiple connection bushing;

mechanically coupling a third tubing to the second top coupling feature of the multiple connection bushing, wherein the third tubing has an inner diameter that is greater than an outer diameter of the second tubing;

inserting the multiple connection bushing, the second tubing, and the third tubing into the wellbore; and

adjusting the pressure within a space between the second tubing, the third tubing, and the multiple connection bushing.

2. The method of claim 1, further comprising:

positioning, after mechanically coupling a second tubing to the first top coupling feature of the multiple connection bushing, at least one centralizer around an outer surface of the second tubing.

3. The method of claim 1, wherein the third tubing has an outer diameter that is less than an inner diameter of a production tubing inserted into the wellbore.

4. The method of claim 1, wherein the second tubing comprises a plurality of second tubing members that are mechanically coupled to each other on an end-to-end basis, and wherein the third tubing comprises a plurality of third tubing members that are mechanically coupled to each other on an end-to-end basis.

5. The method of claim 4, wherein a second tubing member of the plurality of second tubing members is mechanically coupled to the first top coupling feature of the multiple connection bushing before a third tubing member of the plurality of third tubing members is mechanically coupled to the second top coupling feature of the multiple connection bushing.

6. The method of claim 5, wherein, after inserting the multiple connection bushing, the second tubing member and the third tubing member into the wellbore, another second tubing member of the plurality of second tubing members is mechanically coupled to the second tubing member before another third tubing member is mechanically coupled to the third tubing member.

7. The method of claim 1, further comprising:

allowing the second tubing to expand and contract with temperature independent of expansion and contraction of the third tubing.

8. The method of claim 7, wherein the pressure is maintained within the space when the second tubing expands and contracts.

9. The method of claim 1, wherein the working fluid comprises an injection pressure of approximately 3,300 pounds per square inch, wherein the working fluid is injected into an annulus of the first tubing.

10. The method of claim 1, wherein the pressure within the space is adjusted toward zero, and wherein the pressure within the space is substantially uniform along its length.

11. A method for extracting a downhole fluid in a wellbore using vacuum-insulated tubing, the method comprising:

inserting first tubing into the wellbore;

mechanically coupling a bottom coupling feature of a multiple connection bushing to the first tubing, wherein the multiple connection bushing further comprises a first top coupling feature and a second top coupling feature;

mechanically coupling a second tubing to the first top coupling feature of the multiple connection bushing;

mechanically coupling a third tubing to the second top coupling feature of the multiple connection bushing, wherein the third tubing has an inner diameter that is greater than an outer diameter of the second tubing;

inserting the multiple connection bushing, the second tubing, and the third tubing into the wellbore;

adjusting a pressure within a space between the second tubing, the third tubing, and the multiple connection bushing;

inserting a working fluid into a cavity formed by an annulus of the first tubing, a passage through the multiple connection bushing, and an annulus of the second tubing; and

extracting, using completion equipment, production fluid after the working fluid interacts with the production fluid.

12. The method of claim 11, wherein the pressure within the space is adjusted toward zero, and wherein the second tubing has a first temperature that is substantially higher than a second temperature of the third tubing when the working fluid is inserted into the cavity.

13. The method of claim 11, wherein the working fluid has a temperature that exceeds 750° F.

14. A system for adjusting a pressure within a wellbore, the system comprising:

a first tubing disposed within the casing and comprising an open distal end and a proximal end;

a multiple connection bushing mechanically coupled to the proximal end of the first tubing using a bottom coupling feature, wherein the multiple connection bushing further comprises a first top coupling feature and a second top coupling feature;

a second tubing disposed within the casing and mechanically coupled to the first top coupling feature of the multiple connection bushing;

a third tubing disposed within the casing and mechanically coupled to the second top coupling feature of the multiple connection bushing, wherein the third tubing has an inner diameter that is greater than an outer diameter of the second tubing; and

a vacuum system located proximate to a surface and communicably coupled to a space between the second tubing and the third tubing, wherein the vacuum system adjusts a pressure within the space.

15. The system of claim 14, further comprising:

a power source located proximate to the surface;

an injection device electrically coupled to the power source, wherein the injection device is located proximate to the surface, and wherein the injection device is communicably coupled to, and sends a working fluid down, a first cavity formed by an annulus of the second tubing, a passage through the multiple connection bushing, and an annulus of the first tubing; and

completion equipment electrically coupled to the power source and disposed in the wellbore below the first tubing.

16. The system of claim 15, further comprising:

a casing disposed within the wellbore and comprising a plurality of perforations for receiving the production fluid from a reservoir adjacent to the plurality of perforations, wherein the third tubing has an outer diameter that is less than an inner diameter of the casing, and

a cable mechanically coupled to the power source and the completion equipment, wherein the cable is disposed between the casing and the third tubing.

17. The system of claim 14, further comprising:

at least one centralizer disposed between the second tubing and the third tubing, wherein the at least one centralizer is made of a thermally non-conductive material.

18. The system of claim 14, further comprising:

a riser housing positioned atop a wellhead spool above the surface; and

a riser joint mechanically coupled to a proximal end of the second tubing, wherein the riser joint is moveably coupled to, and positioned inside of a channel that traverses, the riser housing.

19. The system of claim 18, further comprising:

a lubricant disposed within a second cavity formed between the riser housing and the riser joint; and

at least one sealing member disposed within a wall of the riser housing between the riser housing and the riser joint.

20. The system of claim 14, wherein the vacuum system comprises a vacuum pump.