SMART FLUID COMPLETIONS, ISOLATIONS, AND SAFETY SYSTEMS

1. FIELD OF THE INVENTION

The disclosure relates to oil and gas exploration and production, and more particularly, but not by way of limitation to systems that employ variable-viscosity fluids to generate well completions, isolations, and safety systems.

2. DESCRIPTION OF RELATED ART

Crude oil and natural gas occur naturally in subterranean deposits and their extraction includes drilling a well. The well provides access to a production fluid that often contains crude oil and natural gas. Generally, drilling of the well involves deploying a drill string into a formation. The drill string includes a drill bit that removes material from the formation as the drill string is lowered to remove material from the formation and form a wellbore. After drilling and prior to production, a casing may be deployed in the wellbore to isolate portions of the wellbore wall and prevent the ingress of fluids from parts of the formation that are not likely to produce desirable fluids. After completion, a production string may be deployed into the well to facilitate the flow of desirable fluids from producing areas of the formation to the surface for collection and processing.

A number of mechanisms may be included in drill strings and production strings to protect equipment within the wellbore and ensure consistent operation such equipment. For example, valves and blow-out preventers may be installed to prevent rapid, excessive increases in pressure and to prevent backflow. In addition, safety equipment may be installed at a wellhead to protect equipment and people in the vicinity of the wellhead in the event of a blowout at the wellhead.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a schematic view of a producing well in which a temporary casing system and isolators are deployed;

FIG. 2A illustrates a schematic view of a subterranean well in which an electrorheological safety system and a smart fluid blowout inhibitor is deployed;

FIG. 2B illustrates a schematic view of a subsea well in which the electrorheological safety system and a smart fluid blowout inhibitor of FIG. 2A are deployed;

FIG. 3 is a schematic, side cross-section view of a temporary casing that includes a smart fluid;

FIG. 4 is a schematic, side cross-section view of a blowout inhibitor that includes a smart fluid;

FIG. 5 is a schematic, side cross-section view of a wellhead insulation system that includes a smart fluid; and

FIG. 5A is a schematic, cross-section view of the system of FIG. 5 taken along the line 5A-5A.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

In the following detailed description of the illustrative embodiments, reference is made to the accompanying drawings that form a part hereof. These embodiments are described in sufficient detail to enable those skilled in the art to practice the invention, and it is understood that other embodiments may be utilized and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the scope of the invention. To avoid detail not necessary to enable those skilled in the art to practice the embodiments described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the illustrative embodiments is defined only by the appended claims.

In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness.

The embodiments described herein relate to systems, tools, and methods for establishing temporary structures in a drilling or production system. In an illustrative embodiment, a temporary wellbore structure, which may be a segment of casing or an isolator, includes a fluid-retaining member having an inner surface and an outer surface. The fluid-retaining member is operable to retain a smart fluid, which may be an electrorheological fluid or a magnetorheological fluid. The temporary structure includes a controller that is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member, which form a field generator that is operable to actuate an electric field or a magnetic field between the inner surface and outer surface of the fluid-retaining member. A surface control subsystem may be communicatively coupled to the controller and to enable a surface-based well operator to actuate the controller.

A smart fluid is disposed within the fluid-retaining member and operable to solidify, gel, or otherwise increase in viscosity upon actuation of the field to increase the rigidity of the fluid-retaining member. The fluid-retaining member may be a sponge, lattice, hollow cylindrical structure, or another suitable structure. The fluid-retaining member is prefilled with a smart fluid in an embodiment. In another embodiment, the system includes a fluid delivery system for delivering a smart fluid to the fluid-retaining member.

The fluid-retaining member may be disposed adjacent a wellbore wall, and therefore operable to form a temporary casing. In another embodiment, the fluid-retaining member may be disposed in an annulus between a production string and a wellbore wall or casing, and operable to isolate a well zone that is downhole from the fluid-retaining member from a well zone that is up-hole from the fluid-retaining member. In another embodiment, the fluid-retaining member is disposed within a production string or a similar segment of tubing, and operable to act as a blowout inhibitor in response to the actuation of the field.

Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to”. Unless otherwise indicated, as used throughout this document, “or” does not require mutual exclusivity.

The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings. Other means may be used as well.

Referring now to the figures, FIG. 1 shows an example of a production system 100 that includes an isolator 105 and temporary casing segment 104, as described in more detail below. The production system 100 includes a rig 116 atop the surface 132 of a well 101. Beneath the rig 116, the wellbore 108 is formed within the geological formation 106, which is expected to produce hydrocarbons. The wellbore 108 may be formed in the geological formation 106 using a drill string that includes a drill bit to remove material from the geological formation 106. The wellbore 108 in FIG. 1 is shown as being near-vertical, but may be formed at any suitable angle to reach a hydrocarbon-rich portion of the geological formation 106. As such, in an embodiment, the wellbore 108 may follow a vertical, partially vertical, angled, or even a partially horizontal path through the geological formation 106.

Following or during formation of the wellbore 108, a production tool string 112 may be deployed that includes tools for use in the wellbore 108 to operate and maintain the well 101. For example, the production tool string 112 optionally includes an artificial lift system to assist fluids from the geological formation to reach the surface 132 of the well 101. Such an artificial lift system may include an electric submersible pump 102, sucker rods, a gas lift system, or any other suitable system for generating a pressure differential. The pump 102 receives power from the surface 132 from a power transmission cable 110, which may also be referred to as an “umbilical cable.”

In a production environment, as shown in FIG. 1, production fluids 146 are extracted from the formation 106 and delivered to the surface 132 via the wellbore 108. As fluid 146 is transported to the surface 132, the fluid passes through the blowout preventer 142 and a fluid diverter 144 that diverts fluid 146 to a collection tank 140 for subsequent processing and refinement.

In such systems, a well operator may monitor the condition of the well 101 and components of the production tool string 112 to ensure that the well operates efficiently and to determine whether the production fluid 146 has desired properties. For example, an operator may want to determine that the production fluid 146 has a high hydrocarbon content and a low water content. In some cases, a well operator may determine that a portion of the formation 106 produces desirable fluids while another portion of the foundation produces undesirable fluids, each such portion of the formation may be referred to as a zone. An operator may similarly determine that different zones within a formation produce fluid at different rates, or that different zones have higher or lower hydrostatic pressure relative to one another. For example, the formation 106 may have a first zone 156 that interacts with the wellbore 108 downhole from a second zone 158. To account for such differing characteristics, an operator may include an isolator 105 for separating the first zone 156 from the second zone to allow for different rates of production or to allow, for example, production of fluid from the first zone 156 without allowing production from the second zone 158. Similarly, to prevent the ingress of fluids from a zone in the formation 106, the system 100 may include a casing 114 or temporary casing 104 that restricts the communication of fluids between the formation 106 and wellbore 108.

In addition, the well operator may take steps to ensure that the pressure in the well does not increase beyond a predetermined threshold, and that pressure within the well or production string 112 does not increase at a rate that is faster than a predetermined rate. Rapid increases in pressure, which may be referred to herein as “pressure spikes” may damage equipment in the production string 112 that is subject to the pressure spike or stress other sealing elements that are designed to contain the well. To account for such pressure spikes and prevent damage to wellbore equipment, the production system 100 may include a blowout inhibitor 124 that prevents such pressure spikes from being transmitted to parts of the production string that are up-hole from the blowout inhibitor 124.

In an embodiment, a surface controller 120 may be communicatively coupled to the temporary casing segment 104, isolator 105, or blowout inhibitor 124 (any of which may be referred to as a “downhole component”) by the cable 110 or by a wireless communication protocol, such as mud-pulse telemetry or a similar communications protocol. The cable 110 may supply power to the downhole component and facilitate the transmission of data between the surface controller 120 and downhole component. In some embodiments, one or more of the downhole components may be permanently or semi-permanently deployed in the wellbore 108, and may include an on-board controller that functions autonomously or that communicates with the surface controller 120 via a wired or wireless communications protocol.

The production system 100 of FIG. 1 is deployed from the rig 116, which may be a drilling rig, a completion rig, a workover rig, or another type of rig. The rig 116 includes a derrick 109 and a rig floor 111. The production tool string 112 extends downward through the rig floor, through a fluid diverter 144 and up-hole blowout preventer 142 that provide a fluidly sealed interface between the wellbore 108 and external environment. The rig 116 may also include a motorized winch 130 and other equipment for extending the tool string 112 into the wellbore 108, retrieving the tool string 112 from the wellbore 108, and positioning the tool string 112 at a selected depth within the wellbore 108.

While the operating environment shown in FIG. 1 relates to a stationary, land-based rig 116 for raising, lowering and setting the tool string 112, in alternative embodiments, mobile rigs, wellbore servicing units (such as coiled tubing units, slickline units, or wireline units), and the like may be used to lower the tool string 112. Further, while the operating environment is generally discussed as relating to a land-based well, the systems and methods described herein may instead be operated in subsea well configurations accessed by a fixed or floating platform. Further, while the downhole components are shown as being deployed in a production environment, the downhole components may be similarly deployed in a drilling environment during the formation of the wellbore 108.

For example, FIGS. 2A and 2B show a system 200 that includes a drill string 212 deployed a well. The well is formed by a wellbore 208 that extends from a surface 232 of the well to or through a subterranean geological formation 206. The well is illustrated onshore in FIG. 2A with the system 200 being deployed in land-based well. In another embodiment, the system 200 may be deployed in a sub-sea well accessed by a fixed or floating platform 221. In the embodiment illustrated in FIG. 2A, the well is formed by a drilling process in which a drill bit 216 is turned by a drill string 212 that extends the drill bit 216 from the surface 232 to the bottom of the well. The drill string 212 may be made up of one or more connected tubes or pipes, of varying or similar cross-section. The drill string may refer to the collection of pipes or tubes as a single component, or alternatively to the individual pipes or tubes that comprise the string. The term drill string is not meant to be limiting in nature and may refer to any component or components that are capable of transferring kinetic, electrical, or hydraulic energy from the surface of the well to the drill bit to remove material from the wellbore. In several embodiments, the drill string 212 may include a central passage disposed longitudinally in the drill string and capable of allowing fluid communication between the surface of the well and downhole locations.

At or near the surface 232 of the well, the drill string 212 may include or be coupled to a kelly 228. The kelly 228 may have a square, hexagonal or octagonal cross-section. The kelly 228 is connected at one end to the remainder of the drill string and at an opposite end to a rotary swivel 233. The kelly passes through a rotary table 236 that is capable of rotating the kelly 228 and thus the remainder of the drill string 212 and drill bit 216. The rotary swivel 233 allows the kelly 228 to rotate without rotational motion being imparted to the rotary swivel 233. A hook 238, cable 242, traveling block (not shown), and hoist (not shown) are provided to lift or lower the drill bit 216, drill string 20, kelly 228 and rotary swivel 233. The kelly 128 and swivel 233 may be raised or lowered as needed to add additional sections of tubing to the drill string 212 as the drill bit 216 advances, or to remove sections of tubing from the drill string 212 if removal of the drill string 212 and drill bit 216 from the well is desired.

A reservoir 244 is positioned at the surface 208 and holds drilling mud 248 for delivery to the well 202 during drilling operations. A supply line 252 is fluidly coupled between the reservoir 244 and the inner passage of the drill string 212. A pump 256 drives fluid through the supply line 252 and downhole to lubricate the drill bit 216 during drilling and to carry cuttings from the drilling process back to the surface 232. After traveling downhole, the drilling mud 248 returns to the surface 232 by way of an annulus 260 formed between the drill string 212 and the wellbore 208. At the surface 232, the drilling mud 248 is returned to the reservoir 244 through a return line 264. The drilling mud 248 may be filtered or otherwise processed prior to recirculation through the well 202.

A wellhead insulation system 204 may be positioned at or near the top of the well to protect equipment and people working in the vicinity in the event of an explosion or other rapid ejection of matter from the well. The wellhead insulation system 204 may include one or more similarly formed wellhead insulation system components that absorb energy and prevent the full force of an explosion from being felt outside of the wellhead insulation system 204.

Referring now primarily to FIG. 3, an embodiment of a downhole component 300 is shown. The downhole component may be a temporary casing, isolator, or other similar component. The downhole component includes a fluid-retaining member, which may be an approximately cylindrical member 302 having an outer surface 304 and an inner surface 306. Each of the outer surface 304 and inner surface 306 includes a conductive layer that is formed from an electrically polarizable material and coupled to either a ground or an electric potential. For example, in the embodiment of FIG. 3, the outer surface 304 is coupled to a ground 308 and the inner surface is coupled to a potential 310. Each of the ground 308 and potential 310 may be provided by a control line 312 that is coupled to, for example, a surface controller, as described above with regard to FIG. 1.

The control line 312 is operable to actuate the potential 310, which generates a charge at the inner surface 306 and a corresponding electric field between the inner surface and the outer surface 304. In an alternative embodiment, the potential 310 may be coupled to an electromagnet that generates a magnetic field between the inner surface 306 and the outer surface 304.

The fluid-retaining member may be a hollow structure, a lattice, a sponge, or any other suitable structure that is capable of holding a fluid, gel, or solidified fluid or gel. The fluid-retaining member may be prefilled with a smart fluid or filled with a smart fluid upon the occurrence of an actuation event, which may be the receipt of a control signal and corresponding potential from the control line 312 or the receipt of an actuation signal from another source, such as an onboard controller or sensor. To fill the fluid-retaining member upon the occurrence of an actuation event, a control signal may be generated to a valved reservoir that forces an adequate amount of smart fluid into the fluid-retaining member to fill all or a portion of the fluid-retaining member upon actuation. The valved reservoir may be analogous to the fluid chamber described below with regard to FIG. 4, and may include a piston that forces fluid from the reservoir into the fluid-retention member upon the occurrence of an actuation event.

As referenced herein, a smart fluid is a fluid having a viscosity that varies in accordance with a stimulus, such as an electric field or magnetic field applied across the fluid. Generally, an electrorheological fluid is a suspension of conductive particles in an electrically insulating fluid. The apparent viscosity of the electrorheological fluid may change reversibly in response to the electric field. For example, a typical electrorheological fluid can go from the consistency of liquid water to a gel, a solid state, or a nearly solid state, and back, with a response times on the order of milliseconds. In an embodiment, the electrorheological fluid comprises urea-coated particles of barium titanium oxalate suspended in silicone oil. Similarly, a magnetorheological fluid is a suspension of magnetic particles in a fluid. The apparent viscosity of the magnetorheological fluid may also change reversibly in response to a magnetic field. Like an electrorheological fluid, a typical magnetorheological fluid can go from the consistency of liquid water to a gel, a solid state, or a nearly solid state, and back, with a response time on the order of milliseconds. In the illustrative embodiments described below, the smart fluid is generally described as an electrorheological fluid. However, the electrorheological fluid and corresponding actuation mechanisms may be substituted for a magnetorheological fluid and actuation structure without departing from the scope of this disclosure.

In the case of the downhole component 300 shown in FIG. 3 actuation of the potential 310 and corresponding electric field may cause an amount of electrorheological fluid stored within the fluid-retaining member to gel or solidify, thereby restricting the ability of other fluids to flow through the area occupied by the actuated electrorheological fluid. This may enable the fluid-retaining structure to function as a temporary casing or as an isolator to restrict flow between zones in a wellbore or to restrict the ingress of fluid from a wellbore at the site of the temporary casing.

FIG. 4 shows an alternative embodiment of a downhole component, as described above with regard to FIG. 1, wherein the downhole component is a blowout inhibitor 400. The blowout inhibitor 400 may be deployed as an element in a production string and may therefore include couplings 432 at either end for joining with tubing segments 430 of a production string. In an embodiment, the blowout inhibitor 400 includes a fluid-retaining member, which may be a hollow tubing segment or similar cylindrical member 402. The cylindrical member may include a fluid chamber 404 that functions as a reservoir to store, for example, an electrorheological fluid 406. The fluid chamber 404 may be enclosed by a valve 411 that separates the fluid chamber 404 from a conduit that passes through the blowout inhibitor 400 and other tubing segments 430 in the production string. The fluid chamber 404 may also include a piston 408 that may be actuated to urge the electrorheological fluid 406 through the valve 411 and into the conduit. An actuator, such as a solenoid 410, may be included to actuate the piston 408.

The solenoid 410 or another type of actuator may be coupled to a controller 412 by a first control line 414. A pressure sensor 416 may be included at the base of the blowout inhibitor 400 or downhole from the blowout inhibitor 400 to detect pressure spikes. The pressure sensor 416 may be coupled to the controller 412 by sensor coupling 418 to generate a signal to the controller 412 that indicates when a pressure spike is detected. Detection of the pressure spike may result in actuation of a field, such as an electric field or magnetic field, by the controller 412.

To generate an electric field, the controller 412 may include or be coupled to a power source, such as a battery or a remote power source. In addition, in an embodiment, the controller 412 is coupled to a conductive inner surface 428 of the cylindrical member 402 or a conductive member 422 having a conductive outer surface 424 to provide an actuation signal, or a potential. In an embodiment, either one of the inner surface 428 of the cylindrical member 402 and the outer surface 424 of the conductive member 422 is coupled to the controller and the other of the inner surface 428 of the cylindrical member 402 and the outer surface 424 of the conductive member 422 is coupled to a ground. A second control line 420 may be provided to couple the conductive member 422 to the controller 412 or to couple the conductive member 422 to a ground. In another embodiment, on or more of the controller 412 and the sensor 416 may be coupled to one another indirectly via a surface controller.

In an embodiment, the electric field of the blowout inhibitor 400 of FIG. 4 may be initiated by the receipt of a control signal from a surface controller or upon determination of a pressure spike by the pressure sensor 416, either of which may be referred to as an initiation signal. In response to an initiation signal, the solenoid 410 may actuate the piston 408 to cause it to force the electrorheological fluid 406 from the fluid chamber 404 to the conduit. The initiation signal may also result in the actuation of the electric field so that, as the electrorheological fluid flows into the conduit, the electrorheological fluid may solidify to restrict the ability of the pressure spike to propagate up the production string to affect other components.

In the event that a pressure spike does reach the surface, resulting in an emission of fluid or another type of explosion, similar systems may be employed to protect people and equipment near the wellhead. An example of such a system is shown in FIG. 5. More particularly, FIG. 5 shows a wellhead insulation system 500 deployed at a wellhead 504. In an embodiment, the wellhead insulation system 500 includes one or more fluid-retaining members 502, which may be a hollow tubing segment or similar cylindrical member, or a segment 522 thereof that is arranged next to an adjacent segment to form an enclosure around the wellhead 504. While the perimeter is shown as being round, the perimeter may alternatively be square, oval, or any other suitable shape. Each fluid-retaining member 502 includes a conductive inner plate 506, a conductive outer plate 508, and functions as reservoir to store, for example, an electrorheological fluid 510.

One of the inner plate 506 and outer plate 508 may be coupled to a controller 512 by a control line 512 and the other of the inner plate 506 and outer plate 508 may be coupled to a ground 520. A pressure sensor 514 may be included in the wellhead 504 to detect a blowout or similar event by, for example, detecting pressure spikes. The pressure sensor 514 may be coupled to the controller 512 by sensor coupling 516 to generate a signal to the controller 512 that indicates when a pressure spike is detected. As described above with regard to the blowout inhibitor of FIG. 4, detection of the pressure spike may result in actuation of an electric field by the controller 412.

To generate a field, the controller 512 may include or be coupled to a power source, such as a battery or a remote power source. In an embodiment, an electric field of the wellhead insulation system 500 of FIG. 5 may be initiated by the receipt of a control signal from a surface controller or upon determination of a pressure spike by the pressure sensor 514, either of which may be referred to as an initiation signal. In an embodiment, the initiation signal results in the actuation of an electric field by causing the controller to apply a potential to one of the inner plate 506 and outer plate 508 so that the electrorheological fluid solidifies gels. Since significant kinetic energy is absorbed when wellbore material collides with the energized electrorheological fluid in the wellhead insulation system 500, the wellhead insulation system 500 will restrict the ability of an explosion to injure nearby equipment or workers.

FIG. 5A shows a top view of the wellhead insulation system 500 of FIG. 5 and illustrates that the wellhead insulation system 500 may be formed in segments 522. Each segment may form a portion of the perimeter that surrounds the wellhead 504. The inner plate 506 and outer plate 508 may be coupled to a common controller in parallel or in series, or may each be constructed with an onboard controller that is coupled to one or more sensors 514 to detect a blowout or similar event.

In another embodiment, empty segments 522 or an empty fluid-retaining structure 502 may be constructed to be a hollow, lightweight component that can easily be transported to a wellhead 504 and filled onsite with an electrorheological fluid, greatly reducing transportation and assembly costs, and providing for easier installation. In an embodiment, the controller 512 may be omitted and the inner plates 506 or outer plates 508 may be coupled to stable potential to maintain the electrorheological fluid in an energizes state, thereby negating the need to detect a blowout in order to protect nearby equipment or personnel.

As an alternative to each of the foregoing embodiments, a corresponding embodiment may be implemented that uses a magnetorheological fluid in place of the electrorheological fluid. In the case of each such alternative embodiment, the structures disclosed may be nearly identical with the exception of the alternative fluid, and the replacement of the structure used to generate an electric field with a corresponding structure that generates a magnetic field. For example, a wound coil that generates an electromagnetic field may be used to apply a magnetic field affect a magnetorheological fluid. In an embodiment in which the fluid retaining structure that houses the magnetorheological fluid comprises parallel surfaces, each surface may include a shielded magnetic plate, or an electromagnet coupled to a magnetizable plate to generate a magnetic field adjacent the plate. In addition, a permanent magnet may be deployed into the magnetorheological fluid to actuate the fluid and increase its viscosity to effect a temporary completion, a blowout inhibitor, or a safety system.

In an embodiment in which a magnetorheological fluid is used, any suitable magnetorheological fluid may be used. The magnetorheological fluid may be, for example, a first composition including 20 wt. % carbonyl iron (CI) and fumed silica stabilizer (“Aerosil 200”) in silicone oil (OKS 1050); a second composition including 40 wt. % carbonyl iron (CI) and fumed silica stabilizer (“Aerosil 200”) in silicone oil (OKS 1050); a third composition including 20 wt. % carbonyl iron (CI) in silicone oil (OKS 1050); and a fourth composition including 40 wt. % carbonyl iron (CI) in silicone oil (OKS 1050); or any other suitable composition. In each of the representative examples, the viscosity of the magneto-rheological fluid varies as a function of magnetic field strength generated by a field generator, such as an electromagnet or a permanent magnet.

In view of the above disclosure, a number of systems and methods relating to the use of electrorheological completions, isolations, and safety systems are provided. For example, in an illustrative embodiment, a system for use in a wellbore comprises a fluid-retaining member having an inner surface and an outer surface, the fluid-retaining member being operable to retain an electrorheological fluid. The system also includes a controller that is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate an electric field between the inner surface and outer surface of the fluid-retaining member. In addition, the system includes a surface control subsystem communicatively that is coupled to the controller and operable actuate the controller. The fluid-retaining member may be a sponge, a lattice or honeycomb, or a porous foam. In an embodiment, the fluid-retaining member is a hollow cylindrical structure.

The fluid-retaining member may be prefilled with an electrorheological fluid, or configured to receive electrorheological fluid from a fluid delivery system that delivers electrorheological fluid to the fluid-retaining member and forms a portion of the system. Electrorheological fluid disposed within the fluid-retaining member may be operable to solidify, gel, thicken, or otherwise vary in viscosity in response to the actuation of the electric field.

In an embodiment, the fluid-retaining member forms a segment of a wellbore casing upon being subjected to the electric field. In another embodiment, the fluid-retaining member forms a blowout inhibitor upon being subjected to the electric field. The blowout inhibitor may be operable to obstruct the flow of fluid in the wellbore beyond the blowout inhibitor, effectively stopping upward flow. In an embodiment, the system further includes a pressure sensor coupled to at least one of the controller and the surface control. The pressure sensor may be operable to monitor a pressure within the wellbore downhole from the fluid-retaining member.

At least one of the controller and the surface control may be operable to generate a control signal that results in actuation of the electric field in response to the pressure sensor determining that the pressure within the wellbore downhole from the fluid-retaining member is greater than a pre-determined threshold, or in response to determining that the pressure within the wellbore downhole from the fluid-retaining member is increasing at a rate that exceeds a predetermined threshold rate. In an embodiment, the system includes a fluid delivery subsystem to deliver an electrorheological fluid to the fluid-retaining member in response to the control signal.

In accordance with another illustrative embodiment, a method for forming a temporary fluid-restraining member in a wellbore includes providing a fluid-retaining member having an inner surface and an outer surface within a wellbore. The fluid-retaining member being operable to retain an electrorheological fluid. The method further includes providing a controller that is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member. In addition the method includes actuating an electric field between the inner surface and outer surface of the fluid-retaining member to energize an electrorheological fluid.

The fluid-retaining member may include a sponge, lattice, or similar structure, and may also include a hollow cylindrical structure resembling, for example, a segment of tubing. The method may further include prefilling the fluid-retaining structure with an electrorheological fluid or delivering the electrorheological fluid to the fluid-retaining member in response to receiving a control signal at the controller. The method may also include causing an electrorheological fluid disposed within the fluid-retaining member to solidify in response to the actuation of the electric field.

In an embodiment, the method includes forming a segment of a wellbore casing with the fluid-retaining member in response to the actuation of the electric field. In another embodiment, the method includes forming a blow-out preventer with the fluid-retaining member in response to the actuation of the electric field. The method may further comprise coupling a pressure sensor to the controller and monitoring a pressure within the wellbore downhole from the fluid-retaining member. In addition, the method may comprise generating a control signal that results in actuation of the electric field in response to determining that the pressure within the wellbore downhole from the fluid-retaining member is greater than a pre-determined threshold, or generating a control signal that results in actuation of the electric field in response to determining that the pressure within the wellbore downhole from the fluid-retaining member is increasing at a rate that is greater than a pre-determined threshold rate. In such an embodiment, the method may further include delivering an electrorheological fluid to the fluid-retaining member in response to the control signal.

According to another illustrative embodiment, a wellhead insulation system includes at least one fluid-retaining member having an inner surface and an outer surface and a controller that is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate an electric field between the inner surface and outer surface of the fluid-retaining member. The wellhead insulation system also includes an electrorheological fluid disposed within the fluid-retaining member. The electrorheological fluid is operable to solidify, gel, or otherwise increase in viscosity in response to the actuation of the electric field. Further, the wellhead insulation system includes an electrorheological fluid disposed within the fluid-retaining member and may include a pressure sensor coupled to the controller. The he pressure sensor being operable to monitor a pressure within a well downhole from the wellhead.

In an embodiment, the fluid-retaining structure is a cylindrical member that forms a circumferential barrier around the wellhead. In another embodiment, the fluid-retaining structure is a series of structures arranged in segments to form a barrier around a wellhead. The series of structures may be a series of hollow plates having conductive layers on each side of the hollow plates.

In an embodiment, the controller is operable to generate a control signal that results in actuation of the electric field in response to determining that the pressure within the well is greater than a pre-determined threshold. In another embodiment, the controller is operable to generate a control signal that results in actuation of the electric field in response to determining that the pressure within the well is increasing at a rate that is greater than a predetermined threshold rate.

In addition to the illustrative embodiments described above, many examples of specific combinations are within the scope of the disclosure, some of which are presented below.

Example One

Example Two

A system for use in a wellbore, the system having a fluid-retaining member having an inner surface and an outer surface, the fluid-retaining member being operable to retain an electrorheological fluid. The system also includes a controller, which is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate an electric field between the inner surface and outer surface of the fluid-retaining member. The system also includes a surface control subsystem communicatively coupled to the controller and operable actuate the controller.

Example Three

A system for use in a wellbore, the system having a fluid-retaining member having an inner surface and an outer surface, the fluid-retaining member being operable to retain an electrorheological fluid. The system also includes a controller, which is magnetically coupled to at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate an electric field between the inner surface and outer surface of the fluid-retaining member. The system also includes a surface control subsystem communicatively coupled to the controller and operable actuate the controller.

Example Four

Example Five

A system for use in a wellbore, the system having a fluid-retaining member having an inner surface and an outer surface, the fluid-retaining member being prefilled with and operable to retain a smart fluid. The system also includes a controller, which is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate a field between the inner surface and outer surface of the fluid-retaining member. The system also includes a surface control subsystem communicatively coupled to the controller and operable actuate the controller.

Example Six

A system for use in a wellbore, the system having a fluid-retaining member having an inner surface and an outer surface, the fluid-retaining member being prefilled with and operable to retain a smart fluid. The system also includes a controller, which is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate a field between the inner surface and outer surface of the fluid-retaining member. The system includes a surface control subsystem communicatively coupled to the controller and operable actuate the controller and also includes a fluid delivery system for the smart fluid to the fluid-retaining member.

Example Seven

Example Eight

Example Nine

Example Ten

A system for use in a wellbore, the system having a fluid-retaining member having an inner surface and an outer surface, the fluid-retaining member being operable to retain a smart fluid. The system also includes a controller, which is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate a field between the inner surface and outer surface of the fluid-retaining member. The system also includes a surface control subsystem communicatively coupled to the controller and operable actuate the controller. In addition, the system includes a pressure sensor coupled to at least one of the controller and the surface control, the pressure sensor being operable to monitor a pressure within the wellbore downhole from the fluid-retaining member. In accordance with the system, at least one of the controller and the surface control is operable to generate a control signal that results in actuation of the field in response to the pressure sensor determining that the pressure within the wellbore downhole from the fluid-retaining member is greater than a pre-determined threshold. The system may also include a fluid delivery subsystem to deliver a smart fluid to the fluid-retaining member in response to the control signal.

Example Eleven

A system for use in a wellbore, the system having a fluid-retaining member having an inner surface and an outer surface, the fluid-retaining member being operable to retain a smart fluid. The system also includes a controller, which is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate a field between the inner surface and outer surface of the fluid-retaining member. The system also includes a surface control subsystem communicatively coupled to the controller and operable actuate the controller. In addition, the system includes a pressure sensor coupled to at least one of the controller and the surface control, the pressure sensor being operable to monitor a pressure within the wellbore downhole from the fluid-retaining member. In accordance with the system, at least one of the controller and the surface control is operable to generate a control signal that results in actuation of the field in response to the pressure sensor determining that the pressure within the wellbore downhole from the fluid-retaining member is increasing at a rate that is greater than a pre-determined threshold rate. The system may also include a fluid delivery subsystem to deliver a smart fluid to the fluid-retaining member in response to the control signal.

Example Twelve

Example Thirteen

Example Fourteen

Example Fifteen

Example Sixteen

Example Seventeen

Example Eighteen

Example Nineteen

Example Twenty

Example Twenty-One

A method for forming a temporary fluid-restraining member in a wellbore includes providing a fluid-retaining member having an inner surface and an outer surface. The fluid-retaining member is operable to retain a smart fluid. The method further includes providing a controller that is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member, and actuating a field between the inner surface and outer surface of the fluid-retaining member. The method further includes forming a blow-out preventer with the fluid-retaining member in response to the actuation of the field. In addition, the method includes coupling a pressure sensor to the controller and monitoring a pressure within the wellbore downhole from the fluid-retaining member.

Example Twenty-Two

A method for forming a temporary fluid-restraining member in a wellbore includes providing a fluid-retaining member having an inner surface and an outer surface. The fluid-retaining member is operable to retain a smart fluid. The method further includes providing a controller that is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member, and actuating a field between the inner surface and outer surface of the fluid-retaining member. The method further includes forming a blow-out preventer with the fluid-retaining member in response to the actuation of the field. In addition, the method includes generating a control signal that results in actuation of the field in response to determining that the pressure within the wellbore downhole from the fluid-retaining member is greater than a pre-determined threshold.

Example Twenty-Three

A method for forming a temporary fluid-restraining member in a wellbore includes providing a fluid-retaining member having an inner surface and an outer surface. The fluid-retaining member is operable to retain a smart fluid. The method further includes providing a controller that is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member, and actuating a field between the inner surface and outer surface of the fluid-retaining member. The method further includes forming a blow-out preventer with the fluid-retaining member in response to the actuation of the field. In addition, the method includes generating a control signal that results in actuation of the field in response to determining that the pressure within the wellbore downhole from the fluid-retaining member is increasing at a rate that is greater than a pre-determined threshold rate.

Example Twenty-Four

A method for forming a temporary fluid-restraining member in a wellbore includes providing a fluid-retaining member having an inner surface and an outer surface. The fluid-retaining member is operable to retain a smart fluid. The method further includes providing a controller that is electrically coupled to at least one of the inner surface and outer surface of the fluid-retaining member, and actuating a field between the inner surface and outer surface of the fluid-retaining member. The method further includes forming a blow-out preventer with the fluid-retaining member in response to the actuation of the field. In addition, the method includes generating a control signal that results in actuation of the field in response to determining that the pressure within the wellbore downhole from the fluid-retaining member is increasing at a rate that is greater than a pre-determined threshold rate, or in response to determining that the pressure is greater than a pre-determined threshold. The method also includes delivering a smart fluid to the fluid-retaining member in response to the control signal.

Example Twenty-Five

Example Twenty-Six

Example Twenty-Seven

Example Twenty-Eight

Example Twenty-Nine

Example Thirty

A wellhead insulation system having at least one fluid-retaining member that includes an inner surface and an outer surface. The system has a power source operable to actuate a field between the inner surface and outer surface of the fluid-retaining member, and a smart fluid is disposed within the fluid-retaining member. The smart fluid is operable to solidify in response to the field. The system further includes a controller that is electrically coupled to the power source and at least one of the inner surface and outer surface of the fluid-retaining member and operable to actuate an electric or a magnetic field between the inner surface and outer surface of the fluid-retaining member. In addition, the system includes a pressure sensor coupled to the controller. The pressure sensor is operable to monitor a pressure within a well downhole from the wellhead.

Example Thirty-One

Example Thirty-Two

It will be understood that the above description of preferred embodiments is given by way of example only and that various modifications may be made by those skilled in the art. The above specification, examples, and data provide a complete description of the structure and use of exemplary embodiments of the invention. Although various embodiments of the invention have been described above with a certain degree of particularity, or with reference to one or more individual embodiments, those skilled in the art could make numerous alterations to the disclosed embodiments without departing from the scope of the claims.

SMART FLUID COMPLETIONS, ISOLATIONS, AND SAFETY SYSTEMS

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