SYSTEM FOR CONTROL AND TREATMENT IN A WELL

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of co-pending U.S. Provisional Application Ser. No. 63/653,536, filed May 30, 2024, the full disclosure of which is incorporated by reference herein in its entirety and for all purposes.

BACKGROUND OF THE INVENTION

1. Field of Invention

The present disclosure relates to wellbore operations, and more specifically to a system that controls devices in a well and provides treatment of the well.

2. Description of Prior Art

Wells for extracting hydrocarbons from subterranean formations commonly include a string of production tubing deployed in the well for directing fluid to surface that is extracted from the formation. These wells are usually lined with casing, which is perforated at depths where the hydrocarbons are trapped within the formation. Packers are generally placed in an annulus between the tubing and casing proximate these depths to prevent the produced fluid from flowing uphole in the annulus. The fluid enters the production tubing through various types of valves, that include inflow control devices and inflow control valves. Gas lift valves are another type of valve that allow communication through the walls of the production tubing and between the annulus and production tubing bore. Gas lift valves are part of a gas lift system used for assisting with the production of liquid from inside a well having insufficient pressure to drive the liquid to surface. Gas lift systems inject lift into the annulus, and selectively inject the lift gas into a column of liquid in the tubing to reduce static head pressure in the column, so that the formation pressure is sufficient to push the liquid and other fluids inside the production tubing to surface.

Many oil and gas wells have production that can be aided with the addition of chemicals. Typical chemicals include foaming agents, corrosion inhibitors, viscosity reducers, and chemicals for generally improving production. Often these chemicals are added into the wells through a small diameter capillary tube that extends from the surface down to the injection point. When designing a chemical injection system, it is advisable that chemical level never drops below the surface into the capillary tube so that a void or vacuum to liquid interface does not form in the capillary tube. If there for any amount of time, many chemicals will evaporate and leave particulates. This in turn clogs the capillary tube and the system will no longer function. Check valves on a capillary tube exit are not fully effective since check valves cannot maintain a fluid column in the capillary tube when annulus pressure drops below hydrostatic pressure in the capillary tube, while relief valves increase injection pump head requirements and can leak over time. Maintaining a chemical level in the capillary tube is also important so that flowrates of chemical additive can be accurately monitored. Because chemical additives are usually costly, amounts of chemical additive injected is generally low; and if not accurately monitored well performance can be reduced.

SUMMARY OF THE INVENTION

Disclosed is an example of a well system for producing fluids from a wellbore that includes a tubular installed in the wellbore, a fluid line having an operating fluid, and a control system selectively changeable to a position in which operating fluid is routed to an injection port in the tubular and is selectively changeable to another position in which operating fluid is routed to a valve that is moveable in response to the operating fluid. The valve is optionally an inflow control valve (“ICV”). Embodiments of the tubular include a production string and wellbore casing. In examples the control system includes a directional valve having a body with multiple passages, in examples of which, moving the body into a first position directs operating fluid from the fluid line to move the ICV into an open configuration so that fluid in an annulus surrounding the production string flows into a bore in the production string. Optionally, the control system includes a surface controlled actuator connected to the directional valve and in an alternative, the ICV includes a sleeve that is slideable within the production string, and has an opening that selectively registers with an opening in the production tubing when in the open configuration. In embodiments, the body is selectively positioned so that operating fluid is directed to the injection port, in an alternative, the body is selectively positioned so that operating fluid in the fluid line is isolated from the injection port, and in another alternative, the body is selectively positioned so that operating fluid from the fluid line to move the valve into a closed configuration so that fluid in an annulus surrounding the production string is isolated from a bore in the production string. In one embodiment, a seal is in the directional valve that is energized by a compressive force exerted by the body. The well system optionally includes a pressure sensor in communication with the fluid line for use in one of diagnostic, verification, or positioning requirements.

Also disclosed is a method of operating a well that includes receiving an operating fluid in the well, treating the well by injecting the operating fluid into the well, and using the operating fluid for actuating a valve in the well. Examples of the operating fluid include a foaming agent, an anti-foaming agent, a biocide, a corrosion inhibitor, a scale inhibitor, an asphaltene inhibitor, an agent to prevent hydrate formation, an adsorbent, an emulsifier, an emulsion breaker, a viscosity reducer, any currently known or later developed agent injected into a well, and combinations. The valve optionally is an inflow control valve that is selectively changed into open and closed configurations by rerouting the operating fluid. The method further includes optionally operating a directional valve to reroute the operating fluid. In examples, the directional valve includes a spool with multiple passages formed within that move in and out of alignment with the fluid line by operating an actuator coupled with the spool. In an alternative, the method further includes automatically calibrating operation of the inflow control valve based on sensing conditions in the well. The method optionally further comprising using multiple stages each with a directional valve and flow control valve or a packer. The method alternatively further includes using multiple stages each with a directional valve and flow control valve or packer, and directing fluid into a single return line.

BRIEF DESCRIPTION OF DRAWINGS

Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which:

FIG. 1A is a side partial sectional view of an example of a well having a surface controlled flow control device.

FIG. 1B is a side partial sectional view of the well of FIG. 1A having another surface controlled flow control device in a deviated portion of the well.

FIGS. 2A and 2B are side sectional views of examples of a production string in a well having a control and injection system.

While subject matter is described in connection with embodiments disclosed herein, it will be understood that the scope of the present disclosure is not limited to any particular embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents thereof.

DETAILED DESCRIPTION OF INVENTION

The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes +/−5% of a cited magnitude. In an embodiment, the term “substantially” includes +/−5% of a cited magnitude, comparison, or description. In an embodiment, usage of the term “generally” includes +/−10% of a cited magnitude.

It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation.

Shown in a side sectional view in FIG. 1 is an example of a well system 10, which includes a production string 12 installed within a wellbore 14 that intersects a subterranean formation 16. The wellbore 14 is lined with casing 18 that has perforations 20 shown projecting radially outward from the wellbore 14 into the surrounding formation 16. In this example, the perforations 20 provide a pathway for fluid F to flow into the wellbore 14 from the formation 16. In the example shown the fluid F is made up primarily of liquid with some small bubbles of gas G mixed within. A packer 22 circumscribes a downhole end of string 12 to block the fluid F from flowing into an annulus 24 between the string 12 and casing 18, and instead directs the fluid F to a bore 25 in the production tubing 12.

The well system 10 includes a lift gas system 26 for assisting the flow of the fluid F uphole within the bore 25 of production tubing 12. An example of a lift gas source 28 is shown on the surface, embodiments of which include an adjacent well, a pipeline, or a vessel. Lift gas source 28 provides lift gas 30, which is shown being injected into the wellbore 14 through an injection line 32. Lift gas 30 inside injection line 32 is at a designated pressure so that the lift gas 30 is forced downhole within annulus 24 to a surface controlled flow control valve (“SCFCV”) 34₁ shown mounted on an outer surface of the production tubing 12. SCFCV 34₁ is intermittently opened to allow the lift gas 30 into the bore 25 of production tubing 12, once in the bore 25, bubbles 35 of lift gas 30 are formed inside the fluid F. The lower density bubbles 35 reduce the density of the fluid F to assist the flow of fluid F uphole inside bore 25 and to a wellhead assembly 36 shown mounted over the wellbore 14 and connected to an end of production tubing 12. Inside wellhead assembly 36, the fluid F is directed to a production line 38 shown attached to a lateral side of wellhead assembly 36. Inside production line 38, fluid F is carried to a location that is offsite for transportation or to a processing facility (not shown). In the example of FIG. 1A, a controller 40 is schematically illustrated outside of wellbore 14 and in signal communication with the SCFCV 34₁ via communication means 42. Examples of communication means 42 include electrically conducting wire, fiber optics, and wireless, such as telemetry. Further optionally included are sensors 44 that are in temperature and pressure communication with annulus 24 and/or bore 25, and which transmit downhole conditions to controller 40 via communication means 42. A specific example of SCFCV 34₁ is what is commonly referred to as a gas lift valve, one example of which unit is described in Wygnanski, U.S. Pat. No. 8,925,638, and which is incorporated by reference herein its entirety and for all purposes.

Another example of a surface controlled flow control valve 342 is shown in a side sectional view in FIG. 1B. In this example, the valve 34₂ is in a deviated or horizontal section of wellbore 14 and mounted in a sidewall of the production string 12, and in a section of the string 12 having an eccentric portion. In an example shown, the valve 34₂ operates in response to command signals received that have been transmitted from surface via communication means 42. In response to the command signals, the SCFCV 34₂ is moved into an opened and/or closed configuration to allow or block fluid communication between the annulus 24 and bore 25. Specific examples of SCFCV 342 include an interval control valve and/or a circulation valve.

Referring now to FIG. 2A, shown in a side sectional view is an example of a production string 210 in the well 14, which includes a control sub 211 equipped with a control system 212. The production string 210 further includes production tubing 214 connected to ends of the control sub 211. In a non-limiting example, the structure and operation of production string 210 is the same or similar to that of string 12 of FIG. 1A, and has an upper end in communication with wellhead assembly 36 and a lower end receiving fluid produced from the surrounding formation 16. A fluid line 216 is shown extending from surface into the well 14 and with a lower end that connects into the sub 211. In the example of FIG. 2A an operating fluid is delivered into the well 14 through the fluid line 216. Embodiments of the operating fluid include a motive fluid for actuating devices downhole and a chemical injection or additive for insertion into the production string 210. Examples of the chemical injection or additive include a foaming agent (to maintain gas bubble size), an anti-foaming agent, a biocide, a corrosion inhibitor, a scale inhibitor, an asphaltene inhibitor, an agent to prevent hydrate formation, an adsorbent, an emulsifier, an emulsion breaker, a viscosity reducer, any currently known or later developed agent injected into a well, and combinations thereof. In this example, chemical injection or additive is from a chemical additive/injection source (not shown), examples of the chemical additive/injection source include a vessel, a pipeline, a tank, a truck, and the like. In this example, injecting the chemical injection or additive into the wellbore 14, such as into the annulus 24 or the production string 210, is for treatment of the wellbore 14, casing 18, string 210, components within the string 210, and/or fluid within the wellbore 14 or string 210. An example of chemical injection is found in Shaw, U.S. patent application Ser. No. 17/987,613, which is assigned to the assignee of the present application, and is incorporated by referenced herein in its entirety and for all purposes. Alternative, the operating fluid is a hydraulic fluid or other fluid useful for actuating devices in the well 14, such as by obtaining a mechanical advantage. Examples exist in which the operating fluid is pressurized, either on surface or by a downhole pump (not shown). Included with the control system 212 is a directional valve 218 shown disposed in the sub 211 and connected to the end of the fluid line 216. Slidably disposed in sub 211 is a sleeve-like inflow control valve (“ICV”) 220, which selectively provides communication between an annulus 222 surrounding string 210 and bore 224 of string 210. Directional valve 218 includes a surface controlled actuator 226 and spool valve 228 shown coupled with an end of actuator 226. An injection line 230 connects between directional valve 218 and an injection port 231 formed through a sidewall of production tubing 214. An optional check valve 232 is provided in injection line 230. Control lines 234, 236 are shown each having an end connected to the directional valve 218. Opposite ends of the lines 234, 236 each connect to an annular cylinder 238 formed in sub 211 where bore 224 has an increased diameter. The ends of lines 234, 236 connect to the cylinder 238 at axially spaced apart locations. For the purposes of discussion herein, fluid line 216, lines 230, 234, 236, and valves 218, 232 form a flow circuit 239. A mid-portion of ICV 220 has an increased diameter to define a piston 240 that is slidable within cylinder 238 between the locations where lines 234, 236 connect to cylinder 238. Openings 242, 244 are formed radially through ICV 220 and sub 211, annulus 222 and bore 224 are in communication when the openings 242, 244 are registered with one another.

Spool valve 228 includes a cylindrical spool 246 (or spool body) within having a series of flow passages 248_{1, 2}, 250_{1, 2}, 252_{1, 2}, 254_{1, 2} formed at different axial locations in the spool 246. Spool 246 is slidable to different positions along an axial direction as depicted by arrow A. Selective positioning of the spool 246, such as by operating actuator 226 from surface, puts fluid line 216 in communication with injection line 230 or lines 234, 236 through passages 248_{1, 2}, 250_{1, 2}, 252_{1, 2}, 254_{1, 2}. In a non-limiting example of operation, the spool 246 is moved to a first position, which aligns an end of passage 248₁ with fluid line 216, aligns an opposite end of passage 248₁ with line 236, aligns an end of passage 248₂ with line 230, and aligns an opposite end of passage 248₂ with line 234. With spool 246 in the first position chemical injection fluid inside fluid line 216 is allowed to flow through passage 248₁ and through line 236 into cylinder 238. Directing pressurized chemical injection fluid into cylinder 238 from line 236 applies a force against piston 240 to urge ICV 220 in a direction away from valve 218 to register openings 242, 244 and put ICV 220 into its open configuration. When openings 242, 244 are in registration, annulus 222 and bore 242 are in communication with one another through the registered openings 242, 244 so that fluid flows from within annulus 222 into bore 224 of production string 216. The fluid is directed to surface once inside bore 224. With the valve spool 246 still in the first position, fluid inside cylinder 238, such as chemical injection fluid or other fluid, is urged into line 234, through passage 248₂, into line 230, across injection port 231, and into bore 224. Further in this example, the spool 246 is selectively moved into a second position by operation of actuator 226. The configuration of FIG. 2A illustrates the valve spool 246 in the second position. In the second position, one end of passage 250₁ aligns with fluid line 216 and an opposite end of passage 250₁ aligns with line 230. In this configuration fluid line 216 and line 230 are in communication with one another through passage 250₁, which provides for direct introduction of chemical injection inside fluid line 216 into bore 224. When the valve spool 246 is in the second position, lines 234, 236 are in communication with one another via passage 250₂. Urging valve spool 246 towards actuator 226 from its second position to a third position (not shown) aligns an end of passage 252₂ with line 234 and an opposing end with line 236, which puts line 234 in communication with line 236 via passage 252₂. When in the third position, opposing ends of passage 252₁ align with line 216 and line 230, but as a mid portion of passage 252₁ is blocked, there is no communication between fluid line 216 and any of lines 230, 234, 236. Putting the valve spool 246 in the third position isolates lines 234, 236 and cylinder 238 from pressurized fluid in line 216, and removes pressurized fluid in line 216 as a source of a motive force to reposition ICV 220. Moving spool 246 further towards actuator from its third position to a fourth position aligns an end of passage 254₁ with fluid line 216 and an opposing end of passage 254₁ with line 234 and aligns an end of passage 254₂ with line 230 and an opposing end of passage 254₂ with line 236. When the valve spool 246 is in the fourth position, pressurized chemical injection fluid within fluid line 216 is flowable through passage 254₁, through line 234, and into cylinder 238 on a side of piston 240 opposite valve 218. The pressurized fluid applies a force onto piston 240 urging ICV 220 towards valve 218 to move ports 242, 244 out of registration with one another and change ICV 220 into the closed configuration shown in FIG. 2A. Moving the ICV 220 into the closed configuration while valve spool 246 is in the fourth position forces fluid in cylinder 238 between piston 240 and valve 218 into line 236, through passage 254₂, into line 230, and then into bore 224 through injection port 231. An advantage of the present disclosure includes using a single fluids carrying line for controlling a downhole valve and also for injecting fluid downhole, which reduces the number of lines in a well. A further advantage is that selective repositioning of a single valve spool 246 controls operation of the ICV 220 as well as fluid injection into the production string 212. In alternatives, fluid inside the flow circuit 239 is a chemical injection fluid, a treatment fluid, a hydraulic fluid, or combinations. Further optionally, fluid inside circuit 239 is replaced by a different fluid by providing the different fluid from surface in line 216 and at a pressure adequate to urge fluid within circuit through check valve 232 and into bore 224. Fluid in lines 234 236 and cylinder 238 is replaced by selectively shifting the valve spool 246 into the different positions.

In FIG. 2B is an embodiment of the production string 210A in which communication between valve 218 and check valve 232 is via line 230₁ and line 230₂. An end of line 230₁ is in selective communication with passages in spool 246 depending on its positioning within valve 218. An opposite end of line 230₁ connects to an end of line 230₂, which has an opposite end connecting to check valve 232. An optional seal 256 is schematically represented at the connection between lines 230₁, 230₂. In alternatives seal 256 is energized by stroking spool 246 of spool valve 228 to a particular position or positions. Energizing seal 256 forms a fluid flow barrier to injection fluid in line 230₁ having leaked between spool 246 and valve housing 258, so that the fluid does not flow into line 230₂. Some directional valves rely on a spool valve that uses close tolerance to resist flow rather than thermoplastic or elastomeric materials to provide a positive seal. In such cases, some fluid can leak over time. This does not pose a problem when pistons are actively being shifted. However, in some configurations it could allow fluid to slowly leak from the chemical injection line. In those situations, in which this becomes a problem, a valve with a positive seal can be added in series to the directional valve. This positive seal would block all flow and have a zero leak rate. In one embodiment, the zero leak valve would be placed at the end of the directional valve via a spring. When the end of the stroke is reached and communication is allowed between each side of the ICV 220 and from line 216 to 230, further stroking the actuator 226 could positively block flow to outlet 231. In another example, the zero leak valve could be placed between the actuator 226 and the spool valve 228. Stroking the directional valve spool and all the way to the right would provide an extra seal meant only to block the chemical flow in line 216. Depending on the directional valve details and seal designs, the separate zero leak valve may or may not be necessary.

In some cases. ICV 220 has flow characteristics that are adjustable and based on position. In this example, a pressure compensated constant flow device (not shown), such as the Flosert device that is commercially available from the Lee Company (https://www.theleeco.com/) is added to line 234 and/or line 236 to make the ICV 220 move at a constant rate. Then the change in position can be determined based on the amount of time the directional valve 218 allows flow of the operating fluid. Optional locations for monitoring fluid pressure include when entering or leaving the directional or in the line—which would offer information such as when the valve is opened and when it reaches the end of the stroke. This in turn would provide the time to fully open the valve (essentially can be calibrated in place). To move a portion of that distance, the directional valve could be opened for a proportional amount of time. In alternatives, this analysis is conducted from the surface, which introduces a time delay in pressure changes downhole versus at the surface through long lengths of small diameter tubing. In examples, based on signals received from sensors 44, controller 40 (FIG. 1A) calibrates internal commands and/or algorithms so that a shifting behavior of the ICV 220 is adjusted. In examples, the calibration is automatic using one or more of conventional techniques, machine learning, and artificial intelligence.

In a non-limiting example of operation, pressure is monitored in one or more of lines 216, 234, 236, or any other relevant line in the circuit. This monitored pressure(s) is used to determine the length of time required to stroke the ICV 220, and that information is used for the purpose of positioning ICV 220. This can optionally be used in conjunction with the above mentioned Flosert pressure compensated constant flow device from the Lee Company. Pressure measurements in the various lines can also be used for diagnostic purposes.

Optionally, the operating fluid is not limited to a chemical injectant, and includes any other operating fluid or fluids. More than one stage can be utilized, for example, the techniques and systems disclosed herein are useful for controlling flow into tubing from one or more zones in a subterranean reservoir. In the example of multiple zones, a packer or other flow barrier is optionally employed between zones. Embodiments of these cases include one or more stages each with a directional valve and flow control valve, and in which flow from each zone is controlled using a single control line with an optional return line. This could also apply to gas or fluid injection into zones. Further optionally, circulation valves (not shown) are included for circulating out fluid after installation of a completion to a fluid of different weight or chemistry. After circulating out the fluid in flow circuit 239, the ICV 220 can be closed. Components of the flow circuit 239 allow for a circulating fluid functionality as well as a surface controlled chemical injection. Yet another application of the production string 210 includes setting a packer (not shown) using a common line. Hydraulic set packers typically utilize tubing pressure to set the packer, which presents difficulties from both a planning and operational perspective. From a planning perspective, all of the other equipment in the well is subjected to the packer setting and test pressures, and the tubing is plugged below the packer to build up pressure. From an operational perspective, there is little feedback as to whether or not a packer has set. The present disclosure allows a hydraulically set packer to be actuated with pressure from the same hydraulic (or chemical injection) line as the completion components in the well.

The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. For example, the control system is useable on any tubular within a well, such as but not limited to wellbore casing, on valves other than ICV's, and any device in a well responsive to a pressurized fluid. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.