Patent Application
20110139465
When a hydrocarbon or other fluid is produced from a subterranean formation, the fluid typically contains particulates or sand. The production of sand from the well is typically controlled in order to extend the life of the well. Gravel packs or screens can be used to filter the particulates of the produced fluids so the fluids without the particulates can be communicated to the surface.
A challenge to using conventional gravel packing operations arises when the fluid of the gravel slurry prematurely separates from the gravel slurry, leaving the gravel behind. This is known as dehydration. When this occurs, a bridge can form in the slurry flow path, forming a bather that prevents slurry upstream of the bridge from being communicated downhole. Bridges can also disrupt and possibly prevent the packing of gravel around some parts of the sand screen, for example, leaving areas in the well devoid of gravel packing.
Another challenge associated with gravel packing operations arises when wellbore equipment, such as a packer, or another obstruction is located within the wellbore. In such cases, the gravel pack conventionally has to be diverted around these obstructions.
One way of overcoming the challenges presented during gravel packing operations is to provide alternative flow paths around obstructions, such as shunt tubes. A shunt tube can have one or more tubes called transport tubes that can deliver slurry to a number of packing tubes located along the wellbore. When a wellbore section is gravel packed, the packing tubes associated with the wellbore section can also be packed off, allowing gravel slurry flow to be diverted further down the wellbore through the transport tubes. Although the packed packing tube diverts most of the flow down the transport tube, a small amount of the gravel slurry fluid can leak through the transport tube into the packed packing tube. This leakage can cause the gravel slurry remaining in the transport tube to dehydrate and can limit the maximum length of the wellbore that can be packed.
Additionally, after one or more sections of the wellbore are gravel packed, hydrocarbons can be produced to the surface through the tubing attached to the sand screen. During production, however, the open packing tubes can allow produced fluids to enter the shunt tube system, which can have an adverse affect on the production of hydrocarbons from the wellbore.
There is a need, therefore, for new apparatus or assemblies that can selectively isolate a transport tube from a packing tube.
Embodiments of the disclosure provide an exemplary packing tube isolation assembly, which includes a first conduit, a second conduit, and a sealing member. The first conduit extends substantially parallel to a longitudinal axis of a tube disposable in a wellbore and has an opening defined in the first conduit. The second conduit fluidly connects to an annulus of the wellbore and to the opening of the first conduit, and is disposed at an angle with respect to the first conduit. The sealing member is disposed adjacent the second conduit and is configured to move into and substantially obstruct the second conduit when the second conduit is at least partially packed with a gravel slurry.
Embodiments of the disclosure also provide a system for gravel packing a well, which includes a tube, first and second packing tube isolation assemblies, and a packer. The tube is at least partially disposed in the well. The first and second packing tube isolation assemblies are disposed around the tube, and each includes a first conduit, a second conduit and a sealing member. The first conduit has an opening formed through a wall thereof. The second conduit is connected to the first conduit around the opening, and is in fluid communication therewith and with the well. The sealing member is disposed adjacent the second conduit and is configured to block the second conduit when a pressure differential between the well and the first conduit reaches an activation level. Further, the packer is disposed around the tube, between the first and second packing tube isolation assemblies.
Embodiments of the disclosure further provide an exemplary method of isolating a packing tube. The exemplary method may include supplying a gravel slurry through a first conduit, and channeling at least a portion of the gravel slurry from the first conduit to a second conduit. The exemplary method may also include distributing the gravel slurry to a portion of an annulus of a wellbore through one or more outlets defined in the second conduit, and actuating a sealing member connected to the second conduit when the second conduit is at least partially packed with gravel slurry. The exemplary method may further include isolating at least a portion of the second conduit from the first conduit with the sealing member.
So that the recited features can be understood in detail, a more particular description, briefly summarized above, may be had by reference to one or more embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
The second conduit 120 can also be or include one or more tubular members or channels defining a second flow path 125 therein. For example, the second conduit 120 can be a packing tube connected to the first conduit 110. The second conduit 120 can also fluidly communicate with an annulus formed between the packing tube isolation assembly 100 and a wall of a wellbore, as shown in, and described below with reference to,
The first flow path 115 can be in selective fluid communication with the second conduit 120. For example, the first conduit 110 can have one or more openings 112 formed therethrough, allowing the first and second conduits 110 and 120 to fluidly communicate. As used herein, the term “selective fluid communication” is generally defined to mean that a flow can be allowed or partially or completely blocked, obstructed, or otherwise attenuated as desired.
In one or more embodiments, the second conduit 120 can have a first portion 122 and a second portion 124 that can be welded, riveted, or otherwise fastened or affixed to the first conduit 110 around the opening 112. The first portion 122 can be disposed at an angle relative to a longitudinal axis of the first conduit 110, such that the first portion 122 of the second conduit 120 is not parallel to the first conduit 110, and at least a portion of the second portion 124 can be substantially parallel to the longitudinal axis of the first conduit 110. The angle of the first portion 122 can be, for example, any angle greater than 0 degrees, and can range from about 0.5 degrees to about 90 degrees, from about 20 degrees to about 70 degrees, or from about 30 degrees to about 60 degrees. The first and second portions 122 and 124 can be provided by a single tubular member that is, for example, bent, or can be two discrete tubular members fixed together at the desired angle, by welding or fastening, for example, using flanges, or the like.
One or more ports or outlets (three are shown 128A, 128B, and 128C) can be formed through the second portion 124 of the second conduit 120. The outlets 128A, 128B, 128C allow fluid communication between the first flow path 115 of the first conduit 110 through the second conduit 120 to an area external to the packing tube isolation assembly 100, as described below with reference to
The second conduit 120 can further include one or more chambers 140 disposed therein. The chamber 140 can be disposed within the second conduit 120, adjacent the first portion 122. The chamber 140 can be in fluid communication with the first flow path 115 and the first conduit 110 via a flow path or inlet 160. The chamber 140 can also be in fluid communication with the exterior of the packing tube isolation assembly 100, such as the annulus 148 of a wellbore, via a flow path or outlet 170, as shown in and described below with reference to
In one or more embodiments, a flow control device 165 can be located in the inlet 160 to allow selective communication between the chamber 140 and the first conduit 110. Illustrative flow control devices 165 can include rupture disks, pressure relief valves, or any other pressure sensitive devices. In another exemplary embodiment, the flow control device 165 can be a dissolvable plug or a solenoid. In another example, the flow control device 165 can be a pressure-sensitive device that is selectively actuatable or opened by exposure to an activation level of pressure differential or another trigger, as described below.
A sealing member 150 can be at least partially disposed within the chamber 140. The sealing member 150 can be any slidable body or member that can move from a first or “open” position within the chamber 140, as depicted in
In at least one specific embodiment, the sealing member 150 can act as a piston that is moveable by applying a force against an upper surface thereof. As depicted in
In at least one specific embodiment, the sealing member 150 can be actuated by pressure within the first conduit 110. For example, when the second conduit 120 is packed or blocked, a pressure differential can form within the first conduit 110. The pressure within the first conduit 110 can rupture or otherwise cause the flow control device 165 to open, thereby placing the flow control device 165 in an open configuration. When the flow control device 165 is in an open configuration, pressure within the first conduit 110 can be communicated to the chamber 140, via the first inlet 160. When the sealing member 150 is axially moved, at least a portion of the sealing member 150 can extend past the chamber 140 and block the opening 112 to the second conduit 120. Accordingly, communication between flow paths 115, 125 can be blocked or prevented.
The outlet 170 can allow fluids such as air or liquids entrained within the chamber 140 to escape, i.e. vent, into the annulus 148 of the wellbore or the flow path 125 when the sealing member 150 moves from the first position to the second position. Such communication can avoid or minimize back pressure that might otherwise impede the progression of the sealing member 150 from the first position to the second position.
In one or more embodiments, the sealing member 150 can be restrained in the first position by a restraining element 151. Illustrative restraining elements 151 can include shear pins or shear screws. Illustrative restraining elements 151 can also include an electrically-actuating element, such as solenoid, or a pneumatically- or hydraulically-actuating element, or the like. In operation, the restraining element 151 can receive a signal to be released, thereby releasing the sealing member 150 from its first position to the second position (
In one or more embodiments, the first and second particulate control devices 352, 354 can be sand control screens. For example, the first and second particulate control devices 352, 354 can be commercially-available screens, slotted or perforated liners or pipes, screened pipes, pre-packed or dual pre-packed screens and/or liners, or combinations thereof. The packer assemblies 370, 380, 385 can include one or more sealing members. For example the packer assemblies 370, 380, 385 can include one or more packers capable of sealing off the annular region or annulus 364 between the completion system 300 and the wellbore 340. Illustrative packer assemblies 370, 380, 385 can include compression or cup packers, inflatable packers, swellable packers, “control-line bypass” packers, polished bore retrievable packers, other common downhole packers, or combinations thereof.
In exemplary operation, the completion system 300 can be conveyed into the wellbore 340, and can be used to perform downhole operations such as gravel packing. The wellbore 340 can have an open or cased borehole. When the wellbore 340 has a cased borehole, the wellbore 340 can have a casing 343. The wellbore 340 can have one or more hydrocarbon producing zones, for example, first and second hydrocarbon producing zones 342, 348.
The completion system 300 can be located within the wellbore 340, such that, in an exemplary embodiment, at least one packing tube isolation assembly 100 can be associated or placed adjacent each of potentially many identified hydrocarbon producing zones. For example, the first packing tube isolation assembly 100A can be located adjacent the first hydrocarbon producing zone 342, and the second packing tube isolation assembly 100B can be located adjacent the second hydrocarbon producing zone 348.
After locating the completion 300 within the wellbore 340, the packer assemblies 370, 380, 385 can be set. The packer assemblies 370, 380, 385 can define first and second wellbore regions 366, 368, by isolating the first and second hydrocarbon producing zones 342, 348 from one another. The packer assemblies 370, 380, 385 can be set by application of pressure, by application of axial force through the tube 305, by swelling, or in other ways known in the art.
In an exemplary embodiment, the packer assemblies 370, 380 can isolate the first hydrocarbon producing zone 342 and define the first wellbore region 366. The packer assemblies 380, 385 can similarly isolate the second hydrocarbon producing zone 348 and define the second wellbore region 368. Consequently, the first wellbore region 366 can be associated with the first hydrocarbon producing zone 342, and the second wellbore region 368 can be associated with the second hydrocarbon producing zone 348.
The first packing tube isolation assembly 100A can be deployed to the first wellbore region 366, and the second packing tube isolation assembly 100B can be deployed to the second wellbore region 368. The particulate control device 352 can be also be deployed to the first wellbore region 366, and the particulate control device 354 can likewise be deployed to the second wellbore region 368. In one or more embodiments, the first conduit 110 of the first packing tube isolation assembly 100A can be configured to extend through the packer assemblies 370, 380 and can connect with the first conduit 110 of the second packing tube isolation assembly 100B. As such, the first conduits 110 of the adjacent packing tube isolation assemblies 100A, B can be in fluid communication with one another. Further, the packer assemblies 380, 385 can seal about the exterior of the portion of the first conduit 110 extending therethrough.
In an exemplary embodiment, after the packer assemblies 370, 380, 385 are set, gravel slurry 390 can be pumped or sent down the first conduit 110 of the first packing tube isolation assembly 100A. The gravel slurry 390 can flow from the first flow path 115 (
The gravel slurry 390 can be supplied to the annular region 364 of the first wellbore region 366, until the gravel slurry 390 at least partially covers or packs the outlet 128 and/or the second conduit 120 of the first packing tube isolation assembly 100A. A pressure differential can be created between the first conduit 110 of the first packer tube isolation assembly 100A and the first wellbore region 366 when at least some of the outlets 128 (e.g., 128A, 128B, 128C of
With additional reference to
The ingress of gravel slurry 390 or other fluids from the first conduit 110 into the space 145 can be propelled by the pressure differential between the first conduit 110 and the packed first wellbore region 366. The ingress of the gravel slurry 390 can urge, propel, actuate, and/or slide the sealing member 150 from the first position to the second position as the gravel slurry 390 enters the chamber 140. In an exemplary embodiment, the sealing member 150 can also, or instead, be urged manually from the first position to the second position using a mechanical device (not shown). The sealing member 150 in the second position can block the second conduit 120 and isolating the flow paths 115, 125 from one another, as shown in
After the sealing member 150 of the first packing tube isolation assembly 100A is actuated, the gravel slurry 390 can flow to lower wellbore regions, such as the second wellbore region 368, as shown in
Gravel packing, as described for the first and second wellbore regions 366, 368, can be repeated for any additional wellbore regions of the wellbore 340. When gravel pack operations of one or more wellbore regions of the wellbore 340 are completed, production operations can be conducted. During production operations, hydrocarbons produced from each of the hydrocarbon producing zones 342, 348 (and any others) can be communicated to the surface, via the tube 305. In one or more embodiments, the completion system 300 can be adapted to allow for selective simultaneous production of hydrocarbons from each hydrocarbon producing zone 342, 348 or hydrocarbons can be independently produced from one or more of the hydrocarbon producing zones 342, 348. For example, flow control devices (not shown) can be disposed about the tube 305 and can be selectively actuated to control the flow of hydrocarbons into the tube 305.
When the activation level of pressure differential is present or it is otherwise desired to move the sealing member 150 to the second position, as described above with reference to
In one or more embodiments, the flapper 200 can be elastically deformed by the movement of the sealing member 150 to second position, such that the flapper 200 essentially fails and releases the sealing member 150. In one or more embodiments, the flapper 200 can be hinged and restrained in the first flapper position by any suitable device, such as a pin, solenoid and/or the like, and then released such that movement of the sealing member 150 to the second position releases the flapper 200.
In one or more embodiments, the sealing member 150 can be urged from the first position (
Accordingly, in one or more embodiments, the amount of force required to move the sealing member 150 from the first position to the second position can be balanced between any combination of components that resist and those that assist the movement of the sealing member 150 from the first position to the second position. For example, the resistance of any combination of the restraining member 151 (
As used herein, the terms “up” and “down”; “upper” and “lower”; “upwardly” and “downwardly”; “upstream” and “downstream”; and other like terms are merely used for convenience to describe spatial orientations or spatial relationships relative to one another in a vertical borehole. However, when applied to equipment and methods for use in deviated or horizontal boreholes, it is understood to those of ordinary skill in the art that such terms are intended to refer to a left to right, right to left, or other spatial relationship as appropriate.
Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.
While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
