Patent Application
20250101834
This disclosure relates to systems and methods for injecting a chemical inhibitor into a wellbore and, more particularly, injecting a chemical inhibitor through a dual-purpose fluid tubing.
Many oil wells tend to develop scale or asphaltene in production string downhole during the course of their producing life. Such wells may need batch or continuous deployment of a chemical inhibitor downhole to inhibit scale and/or asphaltene precipitation. One such method of deploying an inhibitor is to install a specialized set-up for continuous injection of the inhibitor chemical downhole. Installing such a specialized set-up is expensive and requires a workover rig intervention to install a hydraulic line from the surface to the end of a tubing string for circulation of the chemical inhibitor.
In an example implementation, a downhole completion assembly includes at least a portion of a production tubing installed in a wellbore that extends from a terranean surface into a subterranean formation, the production tubing including one or more downhole production valves; a fluid conduit installed in the wellbore adjacent the production tubing, the fluid conduit fluidly coupled, at an uphole end, to a hydraulic fluid source and a chemical inhibitor fluid source, the fluid conduit fluidly coupled, at a downhole end, to the production tubing; and a diverter sleeve installed in or to the fluid conduit. The diverter sleeve is configured to operate: in a first state to circulate a chemical inhibitor fluid from the chemical inhibitor fluid source, through the fluid conduit, and to the production tubing based on a first fluid pressure in the diverter sleeve, and in a second state to circulate a hydraulic fluid from the hydraulic fluid source, through the fluid conduit, and to the one or more downhole production valves based on a second fluid pressure in the diverter sleeve greater than the first fluid pressure.
In an aspect combinable with the example implementation, the diverter sleeve includes an outer housing that includes a connection coupled to the fluid conduit; an inner housing that defines a flow path in fluid communication with the fluid conduit; a first fluid connector fluidly coupled between the flow path and the production tubing; and a second fluid connector fluidly coupled between the flow path and the one or more downhole production valves.
In another aspect combinable with any of the previous aspects, the diverter sleeve includes a plug positioned in the flow path and moveable based at least part on a fluid pressure force in flow path; and a spring positioned to exert a spring force on the plug opposite the fluid pressure force.
In another aspect combinable with any of the previous aspects, in the first state, the first fluid pressure generates the fluid pressure force on the plug, and the spring force is sufficient to urge the plug to fluidly seal the second fluid connector and fluidly couple the flow path to the first fluid connector to circulate the chemical inhibitor fluid through the flow path and to the production tubing.
In another aspect combinable with any of the previous aspects, in the second state, the second fluid pressure generates the fluid pressure force on the plug, and the fluid pressure force is sufficient to urge the plug to fluidly seal the first fluid connector and fluidly couple the flow path to the second fluid connector to circulate the hydraulic fluid through the flow path and to the one or more downhole production valves.
In another aspect combinable with any of the previous aspects, the diverter sleeve includes a pair of uphole flanges including a first uphole flange configured to abut a second uphole flange to limit an uphole movement distance of the plug when the spring force is sufficient to urge the plug to fluidly seal the second fluid connector and fluidly couple the flow path to the first fluid connector.
In another aspect combinable with any of the previous aspects, the diverter sleeve includes a pair of downhole flanges including a first downhole flange configured to abut a second downhole flange to limit a downhole movement distance of the plug when the fluid pressure force is sufficient to urge the plug to fluidly seal the first fluid connector and fluidly couple the flow path to the second fluid connector.
In another aspect combinable with any of the previous aspects, the diverter sleeve includes a fluid outlet formed through the inner housing, where the fluid outlet is positioned to fluidly couple the flow path with the first fluid connector when the spring force is sufficient to urge the plug to fluidly seal the second fluid connector and fluidly couple the flow path to the first fluid connector.
In another aspect combinable with any of the previous aspects, the fluid outlet is positioned to fluidly couple the flow path with the second fluid connector when the fluid pressure force is sufficient to urge the plug to fluidly seal the first fluid connector and fluidly couple the flow path to the second fluid connector.
Another aspect combinable with any of the previous aspects further includes a chemical injection valve fluidly coupled to the first fluid connector and the production tubing.
In another aspect combinable with any of the previous aspects, the diverter sleeve includes one or more seal stacks configured to provide a pressure tight isolation between the outer housing and the inner housing.
In another aspect combinable with any of the previous aspects, the first fluid pressure is between 3,000 and 4,000 psig, and the second fluid pressure is between 9,000 and 10,000 psig.
In another aspect combinable with any of the previous aspects, the hydraulic fluid includes oil, and the chemical inhibitor fluid is configured to remove or reduce scale or asphaltene in the production tubing.
In another example implementation, a method includes operating a production tubing installed in a wellbore that extends from a terranean surface into a subterranean formation to flow a production fluid through one or more downhole production valves of the production tubing; and operating a diverter sleeve installed in or to a fluid conduit that is installed in the wellbore adjacent the production tubing, where the fluid conduit fluidly is coupled, at an uphole end, to a hydraulic fluid source and a chemical inhibitor fluid source and the fluid conduit is fluidly coupled, at a downhole end, to the production tubing. The operating includes operating the diverter sleeve in a first operational mode to circulate a chemical inhibitor fluid from the chemical inhibitor fluid source, through the fluid conduit, and to the production tubing based on a first fluid pressure in the diverter sleeve, and operating the diverter sleeve in a first operational mode to circulate a hydraulic fluid from the hydraulic fluid source, through the fluid conduit, and to the one or more downhole production valves based on a second fluid pressure in the diverter sleeve greater than the first fluid pressure.
In an aspect combinable with the example implementation, the diverter sleeve includes an outer housing that includes a connection coupled to the fluid conduit, and an inner housing that defines a flow path in fluid communication with the fluid conduit.
Another aspect combinable with any of the previous aspects further includes circulating, in the first operational mode, the chemical inhibitor fluid from the flow path to a first fluid connector fluidly coupled between the flow path and the production tubing; and circulating, in the second operational mode, the hydraulic fluid from the flow path to a second fluid connector fluidly coupled between the flow path and the one or more downhole production valves.
In another aspect combinable with any of the previous aspects, the diverter sleeve includes a plug positioned in the flow path and a spring, and the operating includes, in the first and second operational modes, exerting a fluid pressure force on an uphole side of the plug; and in the first and second operational modes, exerting a spring force on a downhole side of the plug opposite the uphole side.
In another aspect combinable with any of the previous aspects, the diverter sleeve in the first operational mode includes moving the plug with the spring force to fluidly seal the second fluid connector and fluidly couple the flow path to the first fluid connector to circulate the chemical inhibitor fluid through the flow path and to the production tubing.
In another aspect combinable with any of the previous aspects, operating the diverter sleeve in the second operational mode includes moving the plug with the fluid pressure force to fluidly seal the first fluid connector and fluidly couple the flow path to the second fluid connector to circulate the hydraulic fluid through the flow path and to the one or more downhole production valves.
In another aspect combinable with any of the previous aspects, operating the diverter sleeve in the first operational mode includes adjusting the diverter sleeve to abut a first uphole flange of an uphole pair of flanges with a second uphole flange of the uphole pair of flanges to limit an uphole movement distance of the plug.
In another aspect combinable with any of the previous aspects, operating the diverter sleeve in the second operational mode includes adjusting the diverter sleeve to abut a first downhole flange of a pair of downhole flanges with a second downhole flange of the pair of downhole flanges to limit a downhole movement distance of the plug.
In another aspect combinable with any of the previous aspects, operating the diverter sleeve in the first operational mode includes moving the plug with the spring force to align a fluid outlet of the inner housing with the first fluid connector to fluidly seal the second fluid connector and fluidly couple the flow path to the first fluid connector.
In another aspect combinable with any of the previous aspects, operating the diverter sleeve in the second operational mode includes moving the plug with the fluid pressure force to align the fluid outlet with the second fluid connector to fluidly seal the first fluid connector and fluidly couple the flow path to the second fluid connector.
In another aspect combinable with any of the previous aspects, operating the diverter sleeve in the first operational mode includes circulating the chemical inhibitor fluid from the first fluid connection to a chemical injection valve in the production tubing.
Another aspect combinable with any of the previous aspects further includes creating a pressure tight isolation between the outer housing and the inner housing with one or more seal stacks.
In another aspect combinable with any of the previous aspects, the first fluid pressure is between 3,000 and 4,000 psig, and the second fluid pressure is between 9,000 and 10,000 psig.
Another aspect combinable with any of the previous aspects further includes removing or reducing scale or asphaltene in the production tubing with the chemical inhibitor fluid circulated in the first operational mode.
Implementations of a systems and methods for a chemical inhibitor system according to the present disclosure may include one or more of the following features. For example, implementations according to the present disclosure can optimize resource utilization by providing a dual use of a smart well completion hydraulic line for continuous chemical injection. As another example, implementations according to the present disclosure can prevent production string and surface facilities from having a scale problem while entailing less capital investment as compared to conventional scale prevention techniques. As another example, implementations according to the present disclosure can double-up as a smart well completion system as well as a continuous chemical inhibitor injection, thereby minimizing a need for the installation of multiple hydraulic lines in a wellbore and consequently, minimizing chances of hydraulic line leaks and well integrity problems.
The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.
The present disclosure describes implementations of a chemical inhibitor system for a well, such as a production well formed from a terranean surface into one or more subterranean formations to produce a fluid (for example, hydrocarbons, water, a combination of hydrocarbons and water, or other fluid) from the subterranean formation(s). Example implementations include a completion assembly as part of a “smart” well set up that includes a fluid conduit operable to supply a hydraulic fluid to operate one or more smart valves within the completion assembly, as well as to supply a chemical inhibitor fluid to the completion assembly to reduce or prevent, for example, scale or asphaltene within a production tubing or string. In some aspects, the chemical inhibitor can be continuously or periodically circulated through the production tubing to prevent such corrosion or scale without the need to install or otherwise use specialized inhibitor injection equipment. In some aspects, a hydraulically operated diverter sleeve on the fluid conduit can operably switch between circulating the hydraulic fluid to the one or more smart valves or supplying the chemical inhibitor fluid to the production tubing.
As shown, the wellbore system 10 accesses a subterranean formation 40, and provides access to hydrocarbons located in such subterranean formation 40, also called reservoir 40. In an example implementation of system 10, the system 10 may be used for a drilling operation as well as a production operation to produce operations as well as supply a chemical inhibitor fluid through the fluid conduit (for example, production string) (described with reference to
As illustrated in
In some embodiments, the assembly 15 may be deployed on a body of water rather than the terranean surface 12. For instance, in some embodiments, the terranean surface 12 may be an ocean, gulf, sea, or any other body of water under which hydrocarbon-bearing formations may be found. In short, reference to the terranean surface 12 includes both land and water surfaces and contemplates forming and developing one or more wellbore systems 10 from either or both locations.
Generally, as a drilling system, the assembly 15 may be any appropriate assembly or drilling rig used to form wellbores or boreholes in the Earth. The assembly 15 may use traditional techniques to form such wellbores, such as the wellbore 20, or may use nontraditional or novel techniques. In some embodiments, the drilling assembly 15 may use rotary drilling equipment to form such wellbores. Rotary drilling equipment is known and may consist of a drill string and a drill bit (or bottom hole assembly that includes a drill bit). In some embodiments, the assembly 15 may consist of a rotary drilling rig. Rotating equipment on such a rotary drilling rig may consist of components that serve to rotate a drill bit, which in turn forms a wellbore, such as the wellbore 20, deeper and deeper into the ground. Rotating equipment consists of a number of components (not all shown here), which contribute to transferring power from a prime mover to the drill bit itself. The prime mover supplies power to a rotary table, or top direct drive system, which in turn supplies rotational power to the drill string. The drill string is typically attached to the drill bit (for example, as a bottom hole assembly). A swivel, which is attached to hoisting equipment, carries much, if not all of, the weight of the drill string, but may allow it to rotate freely.
In some embodiments of the wellbore system 10, the wellbore 20 may be cased with one or more casings. As illustrated, the wellbore 20 includes a conductor casing 25, which extends from the terranean surface 12 shortly into the Earth. A portion of the wellbore 20 enclosed by the conductor casing 25 may be a large diameter borehole. Additionally, in some embodiments, the wellbore 20 may be offset from vertical (for example, a slant wellbore). Even further, in some embodiments, the wellbore 20 may be a stepped wellbore, such that a portion is drilled vertically downward and then curved to a substantially horizontal wellbore portion. Additional substantially vertical and horizontal wellbore portions may be added according to, for example, the type of terranean surface 12, the depth of one or more target subterranean formations, the depth of one or more productive subterranean formations, or other criteria.
Downhole of the conductor casing 25 may be the surface casing 30. The surface casing 30 may enclose a slightly smaller borehole and protect the wellbore 20 from intrusion of, for example, freshwater aquifers located near the terranean surface 12. The wellbore 20 may than extend vertically downward. This portion of the wellbore 20 may be enclosed by the intermediate casing 35.
As a production assembly, the assembly 15 can include certain aforementioned components, as well as a production string or tubing 17 through which a production fluid 42 (for example, hydrocarbons, water, or a combination thereof) can be produced from subterranean formation 40 to the terranean surface 12. As shown in this example, a completion assembly 100 is installed in or as part of the production tubing 17. One or more production seals 55 (such as production tubing packers) can be installed in or adjacent the completion assembly 100 to seal portions of the annulus 60 so as to force production fluid 42 from the subterranean formation 40 into the production tubing 17. In this example, the completion assembly 100 can facilitate a multi-zone completion (with multiple seals 55 and multiple smart valves).
Although not shown in
In some aspects, the assembly 15 (or other portion of the well system 10) may include a flow control system 19, for example, microprocessor-based, electro-mechanical, or otherwise, that can control one or more valves, such as the described downhole smart valves, surface valves, or both. In some aspects, the flow control system 19, as coupled with or as part of the completion assembly 100, may control one or more pumps to circulate the hydraulic fluid, one or more valves, as well as other equipment that is part of or connected to the assembly 15. For example, the flow control system 19 may control a flow rate, pressure, or other circulation criteria of a hydraulic oil that is circulated to the downhole smart valves.
Turning to
As shown in this example, the production assembly 200 includes a wellhead 202 with one or more surface valves 204, as well as one or more TCA (tubing/casing annulus) valves 206. The TCA valve 206 is fluidly coupled to the annulus 60 of the wellbore 20, while the production tubing 17 extends through the wellbore 20 and is fluidly decoupled from the annulus 60.
As shown in this example, production seals 208 (such as production packers) are installed about the production tubing 17 in the annulus 60 to create, in this example, a multizone production scheme in which production fluid enters the annulus 60 through one or more fractures 80 (for example, natural, hydraulic, or both) created in the subterranean formation 40. The production seals 208 ensure that the production fluid 42 is directed from the fractures 80 into the production tubing 17 through one or more downhole valves 214.
As shown in this example, a fluid conduit 210 extends from the terranean surface 12 (for example, from or connected to the flow control system 19) into the wellbore 20 and adjacent the production tubing 17. In this example, the fluid conduit 210 is connected through connections 216 to the downhole valves 214. The fluid conduit 210, in operation, circulates a hydraulic fluid 212 (such as oil) from the terranean surface 12 (such as from the flow control system 19) to operate the downhole valves 214. In operation, the flow control system 19 circulates (for example, automatically on a schedule) the hydraulic fluid 212 at a specified hydraulic pressure, such as between 9,000-10,000 psig, to the downhole valves 214 (one, some, or all, regardless of the number of valves 214 within the production assembly 200). When circulated at the specified pressure, the downhole valves 214 can modulate, such as from closed to open to allow the production fluid 42 into the production tubing 17.
In some aspects, the chemical injection system 302 is or includes a chemical inhibitor pump operable to circulate the chemical inhibitor fluid 306 into the fluid conduit 210 at a specified pressure. The specified pressure can be, for example, set or determined according to operation of a chemical injection valve 312 that is located downhole within the production tubing 17 (in this example, uphole of the downhole valves 214) and fluidly coupled to the fluid conduit 210. In some aspects, for example, the chemical injection valve 312 can be operated (for example, modulated from closed to open) based on a specified pressure that is less than the specified hydraulic pressure that operates the downhole valves 214. In example implementations, the specified pressure that operated the chemical injection valve 312 can be, for instance, between 3,000 and 4,000 psig.
As explained more fully with reference to
As shown in
The example implementation of the diverter sleeve 310 includes a biasing member 330 (such as a spring, Belleville washers, or other component) that is positioned at a downhole end of the diverter sleeve 310 within the flow path 326 and inside of the inner housing 322. Further positioned within the flow path 326 is a plug 328 that is attached to or integral with the inner housing 322.
As further shown in
As noted,
Further, in this state, the upper flange sleeve 336 abuts the upper restraining flange 332 to limit the uphole movement of the inner housing 322 (and thus the plug 328). Chemical inhibitor fluid 306 is circulated from the flow path 326, through the connection 315, and to the chemical injection valve(s) 312 for the production tubing 17.
In some aspects, as long as the chemical inhibitor fluid 306 is circulated at or near the particular pressure, Pc, the diverter sleeve 310 remains in the first state, thereby continuously supplying chemical inhibitor fluid 306 to the production tubing 17. If a flow of the chemical inhibitor fluid 306 ceases or is circulated at a pressure much less than the particular pressure, Pc, the diverter sleeve 310 can still remain at the first state as shown in
In this example implementation, the spring force, F, of the biasing member or spring 330 is compressed by the pressure, PH, such that the plug 328 is urged in a downhole direction to align the outlet 340 with the connection 216 as shown. In this state, the outlet 340, which is formed in the inner housing 322, becomes aligned with the connection 216 (but is misaligned with the connection 315) to allow fluid communication between the flow path 326 and the connection 216, but not allow fluid communication between the flow path 326 and the connection 315.
Further, in the second state, the lower flange sleeve 338 abuts the lower restraining flange 334 to limit the downhole movement of the inner housing 322 (and thus the plug 328). Hydraulic fluid 212 is circulated from the flow path 326, through the connection 216, and to the downhole valves 214 to allow the circulation of production fluid 42 into the production tubing 17 from the subterranean formation 40.
In some aspects, as long as the hydraulic fluid 212 is circulated at or near the particular pressure, PH, the diverter sleeve 310 remains in the second state, thereby allowing production fluid 42 to flow into the production tubing 17. If a flow of the hydraulic fluid 212 ceases or is circulated at a pressure much less than the particular pressure, PH, such as a pressure that is less than the spring force, F, the diverter sleeve 310 reverts to the first state as shown in
A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.
