This disclosure provides methods, systems and devices for re-directing flow through tubing in a well, inside other tubing, or other enclosed space.
Tools incorporating valve assemblies having a plug, such as a ball or dart, and a plug seat, such as a ball seat or dart seat, have been used for a number of different operations in wells for oil gas and other hydrocarbons. These tools may be incorporated into a string of pipe or other tubular goods inserted into the well. The valve assemblies provide a defined location at which the flow of fluid past may be obstructed and, with the application of a desired pressure, a well operator can actuate one or more tools associated with the assembly.
Remotely operated valve assemblies may be used in the treatment of a subterranean formation adjacent to a well. Valves used for this purpose open ports in the tubing to facilitate treatment of a selected area or section of the formation. The treatments are performed by pumping fluid through the wellhead, into the tubing string and out of the selectively opened ports. Examples of such well treatments include acidizing or fracing. Acidizing cleans away acid soluble material near the well bore to open or enlarge the flow path for hydrocarbons into the well. Fracing may occur by injecting fluids from the surface through the wellbore and into the formation at high pressure to create and force fractures to open wider and extend further. The injected frac fluids may contain a granular material, such as sand, which holds fractures open after the fluid pressure is reduced. Such granular materials are not necessarily required, however. While acidizing and fracing are two examples of treatments that may be performed through the valve assemblies, the scope of the present disclosure is not limited to any particular formation treatment(s) and may include any other treatment, such as, without limitation, CO2 injection, treatment with scale inhibitors, iron control agents, corrosion inhibitors or others.
Treatments in multiple-stage production wells may require selective actuation of downhole tools, such as sleeve assemblies, to control fluid flow from the tubing string to the formation. For example, U.S. Pat. No. 7,926,571 entitled Cemented Open Hole Selective Fracing System, which is incorporated by this reference, describes a system using multiple valve assemblies having ball-and-seat seals, each having a differently sized ball seat and corresponding ball. Such ball-and-seat arrangements are operated by placing an appropriately sized ball into the well bore and bringing the ball into contact with a corresponding ball seat. The ball engages on a section of the ball seat to block the flow of fluids past the valve assembly. Application of pressure to the valve assembly, such as through use of fluid pumps at the surface, may create a pressure differential across the valve assembly, causing the valve assembly to “shift” and thereby open fluid flow the sleeve to the surrounding the formation. Other types of plugs such as darts, or any other shape that can be used to selectively operate the valve assemblies, may also be used to seal the seat and facilitate the creation of a pressure differential to shift the valve assembly and open the sleeve, or actuate a different tool, such as a plug and seat actuated flapper valve, associated with the valve assembly.
If the well or tubing contains multiple plug seats, methods, systems or apparatuses must be employed for passing a plug through certain plug seats, including passing through at least some plug seats without actuating any devices associated with such seats. One such method is to use a ball, dart or other plug that is small enough so that it will not seal against any of the seats it encounters prior to reaching the desired seat. For this reason, the smallest ball to be used for the planned operation is the first ball placed into the well or tubing and the smallest ball seat is positioned in the well or tubing the furthest from the wellhead. After the desired treatments are completed, the direction of fluid flow is reversed so that the treating fluids and formation fluids may be produced through the wellhead. Because each plug is smaller than the seats past which it traveled, the plugs simply move with the fluids through the previously passed plug seats and out of the well.
Valve assemblies, which rely solely on the size of the plug and the seat opening for selecting the tool to actuate, significantly limit the number of valves that can be used in a given tubing string. In such systems each ball size is only able to actuate a single valve and, generally, each plug must have a diameter of at least 0.125 inches larger than the immediately preceding plug. Thus, the size of the liner restricts the number of valve assemblies with differently-sized ball seats.
Devices and assemblies have been introduced to increase the number of valve assemblies that may be actuated by a single plug, such as a ball, dart, or other plug. Such devices and assemblies include those described in U.S. application Ser. No. 12/702,169, filed Feb. 28, 2010 and entitled “Downhole Tool With Expandable Seat;” U.S. application Ser. No. 13/423,154, filed Mar. 16, 2012 and entitled “Downhole System and Apparatus Incorporating Valve Assembly With Resilient Deformable Engaging Element;” and U.S. application Ser. No. 13/423,158, filed Mar. 16, 2012 and entitled “Multistage Production System Incorporating Downhole Tool With Collapsible or Expandable C-Ring,” each of which is incorporated herein by reference. The devices, methods, and assemblies described in these applications, however, place one or more plugs downstream of plug seats with openings smaller than the diameter or other cross sectional dimension of the plug. When the fluid flow is reversed, i.e., fluid begins flowing toward the wellhead, such plugs may seat on the back or outlet side of a previously passed plug seat, blocking the reverse flow. The methods for removing such blockages, such as drilling out the tubing string, are both time consuming and expensive. Therefore, there exists a need for cost effective and time efficient devices and/or methods for circumventing such blockages and thereby allowing the flow of fluids from the well bore to the surface.
The present disclosure describes systems, methods, and apparatuses for allowing fluid flow to bypass such a blockage. Further, the bypass of such present disclosure is not limited to blockages caused by plugs traveling upstream. Rather, the bypass may operate in response to any event or events that limit flow and/or create a pressure differential at a pre-identified point in the tubing string.
In some embodiments of the present disclosure, it is desirable that the flow bypass remain closed until a pre-determined triggering event has occurred. Such triggering events include, without limitation, shifting of a valve assembly in response to a pressure differential across that valve assembly. Therefore, the present disclosure further encompasses valve assemblies including a sequencing mechanism which prevents fluid from flowing through the bypass assembly until after the pre-determined triggering event has occurred. The sequencing mechanism may be a locking assembly configured for use in a tubing string to prevent actuation of one or more tools until after the lock is released. Further, the locking mechanism may be used in connection with the flowback bypass of the present disclosure, though the locking mechanism of the present disclosure is in no way limited to use with the flowback bypass or any other specific tool, method, or assembly.
Embodiments of this disclosure generally provide devices, methods and systems for use in a tubing string. An apparatus of the present disclosure may comprise a housing, with an interior passage for the flow of fluids, an obstruction in the interior passage, and a flow bypass around the obstruction. The obstruction is preferably a plug seat, but may be any feature of the tubing or apparatus that may obstruct, or cooperate with fluids or solids in the tubing to obstruct, fluid flow towards the wellhead. In other words, the obstruction may not prevent fluid flow by itself, but instead define a location at which fluid flow may be blocked during operations performed using, in, or on the tubing string. The flow bypass may be blocked by a barrier, and the barrier may be held in place, either wholly or partially, by a locking mechanism. In certain embodiments, such locking mechanism is released in response to a particular event, such as a predetermined pressure differential created across the plug seat, preferably with the higher pressure occurring on the wellhead side of the plug seat. The bypass is then allowed to open in response to a pressure differential across the plug seat in the opposite direction.
A method of the present disclosure may include engaging a first plug on an uphole side of a first plug seat in a first sleeve assembly and opening, at least partially, a first set of ports located on the first sleeve assembly. Further, a second plug may be engaged on a downhole side of the first plug seat, and opening, at least partially, a second set of ports on the first sleeve assembly, wherein at least part of a fluid flow passes through the second set of ports to exit the first sleeve assembly, bypasses the first plug seat and re-enters the first sleeve assembly at the first set of ports.
In another embodiment, a system includes a first plug engaging an uphole side of a first plug seat in a first sleeve assembly. Further, the system includes a first set of ports at least partially opened on the first sleeve assembly. Further still, the system includes a change, subsequent to the first set of ports being opened, of a fluid flow to upstream in the tubing string. Yet further, the system includes a second plug engaging a downhole side of the first plug seat, and a second set of ports at least partially opened on the first sleeve assembly, wherein the fluid flow bypasses the first plug seat.
So that the manner in which the above recited features, advantages and objects of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings.
It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
a depicts a tubing string installed in a well, showing the relative locations of a a first sleeve assembly and a second sleeve assembly.
b conceptually illustrates a cross section from the first sleeve assembly of
c conceptually illustrates a cross section from the second sleeve assembly if
a depicts a flowback bypass device after the plug seat and first sleeve have been shifted by a differential pressure created across the plug seat.
b depicts an enlargement of a portion of the flowback device from
The following is a detailed description of example embodiments of the invention depicted in the accompanying drawings. The amount of detail offered is not intended to limit the anticipated variations of embodiments; on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the present disclosure as defined by the appended claims. The detailed descriptions below are designed to make such embodiments obvious to a person of ordinary skill in the art.
Generally speaking, methods and systems for use in a tubing string are contemplated. The methods and systems permit mechanical control of fluid flow from a wellhead to a formation through use of at least two plugs, such as plugs, balls or darts, wherein the plugs are optionally dissimilar. Further, the methods and systems provide for a flow bypass around a plug that may be trapped in the tubing string. The fluid, of course, may comprise treating fluids, hydrocarbons, water, impurities or other mined substances, for example, which may be carried to the wellhead through use of solutions under pressure. The substances comprising the fluid may or may not be completely or partially dissolved, and may exist in one or more physical states of gas, liquid, or solid.
Turning to the drawings,
In the illustrated embodiment, the housing 105 comprises multiple sections, including a crossover section 180. The various sections of the housing of the illustrated embodiment are present for purposes of assembling the tool and are not required as part of the present disclosure. Thus, the housing of the illustrated embodiments may be of one piece of or a plurality pieces.
The embodiment of
Turning to
Plug seat 160 comprises an inlet 162 and an outlet 164. The inlet 162 generally comprises the surface of the plug seat 160 that fluids, a plug, or other materials will first encounter when travelling from a well head or from fluid pumps positioned at an end of the tubing string. The inlet 162 will also typically function as the plug seat 160 surface against which a plug traveling from the well will form a seal. It will be apparent that, in the illustrated embodiment, the illustrated shear pins 101 will generally be broken as a result of a pressure differential across the plug seat 160 where the fluid pressure is higher at the inlet 162 than at the outlet 164.
Additional features of the embodiment illustrated by
As shown in
With reference to
It will be appreciated that a shear pin may be included that will break at a pressure below the pressure required for the plug to extrude and that the plug will actuate the tool prior to moving between the first sleeve assembly and second sleeve assembly. Such an arrangement is within the scope of the present disclosure.
The first plug 225 may encounter a second assembly 210, which, generally speaking, will not allow the plug 225 to pass further through the tubing string. For example, the passage through a second plug seat 265 in the second assembly 210 may be too small for extrusion of the plug 225 at the pressure differentials created across the plug 225 and second plug seat 265. The second assembly 210 may be a second sleeve assembly, a plug and plug seat actuated flapper valve, any other plug and plug seat actuated tool, a blind plug seat with no associated tool, or any other device for stopping travel of the plug 225 through the tubing string.
a and 5b depict the illustrative embodiment of
A second plug may then engage the plug seat 360. The second plug may be selected such that it will not extrude through plug seat 360 until the pressure differential across the plug seat 360 exceeds the pressure required to break the at least one shear pin 301. Therefore, rather than extrude the second plug through the plug seat 360, the at least one shear pin 301 is broken allowing the plug seat 360 as well as the attached first sleeve 310 and the locking section 370 to move in the downward direction. This movement of plug seat 360 and first sleeve 310 opens the first set of ports 330 thereby creating fluid communication between the passageway through the assembly and the exterior of the assembly and facilitating treatment of the adjacent formation. The second sleeve 320 remains closed in this embodiment so that fluid may not flow around the ball seat and back into the tubing string rather than into the adjacent formation or other areas to be treated. The first plug 225 and second plug 327 of the illustrative embodiment may each be selected based on their respective sizes relative to the plug seats, the material or materials from which a selected plug is manufactured, combinations of the above, or any other factor provided that the selected plug performs the desired function of sealing against the plug seat 360 and either extruding through the plug seat 360 at a pressure differential insufficient to break the at least one shear pin 301 or maintaining its seal with plug seat 360 up to at least a pressure differential sufficient to break the at least one shear pin 301.
When locking sleeve 370 shifts, the recessed surface 374 is brought adjacent to the ball 620 of locking mechanism 600, such that ball 620 now has sufficient clearance to fit between recessed surface 374 and the stationary bar 630, unlocking the locking mechanism. Further, the locking sleeve 370 and second sleeve 320 are now interlocked through adjoining their complimentary portions of wicker teeth 350, connecting these two sleeves. It will be apparent that any adjoining method or system is acceptable and is not limited to teeth as described herein. For example, the sleeves 310, 320 may permanently or temporarily interlock by use of retaining rings, locking rings, gears, or any other method of joining the ends upon movement of the locking sleeve 370 relative to the second sleeve 320.
Moving on to
Finally, with reference with
The embodiment locking mechanism illustrated in the figures is shown such that the moveable bar moves parallel to the longitudinal axis of the tubing string upon release of the lock. However, the locking bar, moveable bar, bolt, and stationary bar may also be arranged to prevent rotational movement around a circumference or perimeter of the tubing string. Further, the direction in which the locking bar moves does not necessarily dictate the direction of movement the locking bar prevents, e.g., a locking bar may hold a tab in place to prevent rotation movement of the locked piece.
Further, it will be appreciated that the ball 620 acts as a bolt, cam, or similar restrictor element of a lock to create communication between the generally moveable sleeve lock 630 and the generally stationary housing lock 610, thereby immobilizing the sleeve lock 630. Other bolts or cams, including dogs, collets, pins, bars, or other structure, may be substituted for the ball 620 provided that such structure engages or otherwise causes mechanical communication between a stationary element and a moveable element, and is removeable from such engagement or communication upon movement of the support structure or support element.
Additionally, the illustrated embodiments show the obstruction in the passageway is bypassed by flowing fluids along the exterior of the tubing, but other arrangements are within the scope of the present disclosure. For example, the bypass around the obstruction in the passageway may be contained within the housing, between a valve seat and the housing, or other arrangement that provides fluid communication around the obstruction.
The embodiments of the present disclosure may be used in both open hole and cemented tubing strings. In cemented tubing applications, the well treatments may be used to mechanically break, dissolve, or otherwise create a flow path through the cement connecting the first and second at least one ports along the outside of the assembly. In other embodiments, the first and second at least one port may be connected.
While the foregoing is directed to example embodiments of the present disclosure, 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.
This application is a continuation-in-part of U.S. patent application Ser. No. 13/423,154 filed on Mar. 16, 2012 and entitled “Downhole System Incorporating Valve Assembly with Resilient Deformable Engaging Element”, which claims the benefit of U.S. Provisional Application Ser. No. 61/453,281 filed Mar. 16, 2011 and entitled “Multistage Production System Incorporating Downhole Tool with Deformable Ball” and a Continuation of U.S. patent application Ser. No. 13/694,509 filed on Dec. 12, 2012; all of which are incorporated by reference herein.
Number | Date | Country | |
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61453281 | Mar 2011 | US |
Number | Date | Country | |
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Parent | 13694509 | Dec 2012 | US |
Child | 13423154 | US |
Number | Date | Country | |
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Parent | 13423154 | Mar 2012 | US |
Child | 14301020 | US |