Patent Publication Number: US-10787884-B2

Title: Downhole tool having a dissolvable plug

Description:
CLAIM OF PRIORITY 
     This application claims priority to Norwegian Patent Application No. 20170824, filed May 19, 2017. The disclosure of the priority application is hereby incorporated in its entirety by reference. 
     The present invention relates to a downhole tool, and more particularly to a valve tool suitable for use in well completion and/or hydraulic fracturing operations. 
     BACKGROUND 
     When completing a petroleum well, i.e. preparing it for production, it is common to install one or more tubulars, such as casing, into the wellbore and cement the tubular in place. Such cementing operations include pumping cement down into the well through the tubular and causing it to flow upwardly and fill an annulus space between the tubular and the wellbore. When the required volume of cement has been pumped down into the well, the tubular is frequently “wiped”, by pumping a wiper device down through the tubular. The wiper device may be, for example, a wiper dart. 
     After cementing, the well needs to be openend for production. This is commonly done using a so-called “toe valve”. The toe valve may be pressure-activated, i.e. be activated through pressurizing of the tubular. U.S. Pat. No. 9,476,282 B2 describes an example of such a toe valve, in which a valve sleeve is arranged in a chamber defined by a first sub, a second sub and a housing. A pressure barrier, such as a rupture disc, is used to control the activation of the toe valve. 
     Such valves are subjected to challenging downhole conditions prior to their activation. This includes exposure to high pressures and temperatures, various well fluids, as well as to the cement during the cementing operation. It can therefore be a challenge to ensure that the toe valve activates properly and at the desired time. It is also desirable that such valves provide high integrity and operational safety of the well, and, for example, allow pressure testing of the well during or after completion, for example after the cementing operation. There is therefore a continuous need for improved solutions and techniques in relation to such valves and such completion operations. 
     The present invention has the objective to provide an improved tool for use in well completion and fracturing operation, which provide advantages over known solutions and techniques in reliability, operational safety or other aspects. 
     SUMMARY 
     In an embodiment, there is provided a downhole valve having: a valve body with a longitudinal main passage; an annular chamber arranged in the valve body; at least one valve port extending from the main passage, through the annular chamber and to an outside of the valve; and a sleeve disposed at least partially within the chamber, the sleeve being movable in response to an application of fluid pressure to the annular chamber via a fluid channel extending from the main passage to the annular chamber between a closed position in which the sleeve blocks the at least one valve port and an open position in which the sleeve does not block the at least one valve port. 
     In an embodiment, there is provided a downhole tool having: a body; 
     an activation element arranged within the body; a fluid channel extending from an opening in the body to the activation element; at least one dissolvable plug sealingly arranged in the fluid channel; and at least one breakable fluid barrier sealingly arranged in the fluid channel. 
     In an embodiment, there is provided a tubular assembly for use in a wellbore, the tubular assembly comprising a first downhole tool and a second downhole tool, wherein the first downhole tool has a higher number of dissolvable plugs and a higher number of breakable fluid barriers than the second downhole tool. 
     In an embodiment, there is provided a method of completing a well, comprising the steps of: deploying a tubular comprising a downhole valve into a wellbore; pumping cement through the tubular and into an annulus between the tubular and a formation; causing a dissolvable plug to degrade, disintegrate or dissolve; actuating a valve by applying a fluid pressure to the annular chamber via a fluid channel; and flowing a fluid through at least one valve port. 
     Further embodiments are set out in the following detailed description and in the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Illustrative embodiments of the present invention will now be described with reference to the appended drawings, in which: 
         FIG. 1  illustrates a valve according to an embodiment, 
         FIG. 2  illustrates parts of a wellbore completion, 
         FIGS. 3-5  illustrate the valve shown in  FIG. 1  in different operational states, 
         FIG. 6  illustrates a valve according to an embodiment, 
         FIG. 7  illustrates a valve according to an embodiment, 
         FIG. 8  illustrates a valve according to an embodiment, 
         FIG. 9  illustrates a valve according to an embodiment, 
         FIG. 10  illustrates a valve according to an embodiment, and 
         FIG. 11  illustrates aspects of a tool according to an embodiment. 
     
    
    
     DETAILED DESCRIPTION 
     In an embodiment, illustrated in  FIG. 1 , a downhole valve  1  is provided. The valve  1  has a body  10  with a longitudinal main passage  11 , and is arranged for connection to a tubular pipe, such as a well tubing or a well casing (not shown) at end sections  1   a  and  1   b . The valve body  10  is made up of a first sub  10   a  defining a first part of the main passage  11  and a second sub  10   b  defining a second part of the main passage  11 . The first sub  10   a  and the second sub  10   b  are mechanically connected with a threaded connection  40 . Suitable seals and packers  41 , 42  are arranged between the first sub  10   a  and the second sub  10   b.    
     An annular chamber  12  is defined in the valve  1 , in the embodiment shown here the annular chamber  12  is provided radially between sections of the first sub  10   a  and the second sub  10   b . The second sub  10   b  comprises a protruding portion  71  extending into the first sub  10   a  and the annular chamber  12  is provided between an outside of the protruding portion  71  and an inner circumference of the first sub  10   a . A plurality of ports  13   a - e  extend radially through the valve body  10 , in this embodiment through the protruding portion  71  and the circumferential wall of the first sub  10   a , between the main passage  11  and an outside of the valve  1 . The annular chamber  12  is arranged so that the ports  13   a - e  extend through the annular chamber  12 . 
     An annular sleeve  14  is disposed at least partially within the chamber  12 , the sleeve  14  being movable axially (in relation to the longitudinal axis of the valve  1 ) between a closed position in which the sleeve  14  blocks the valve ports  13   a - e  and an open position in which the sleeve  14  does not block the valve ports  13   a - e . In  FIG. 1 , the sleeve  14  is shown in the closed position. Appropriate seals  18   a - d  are provided to seal between the chamber  12  walls and the sleeve  14  such that a fluid tight sealing can be obtained between the main passage  11  and the outside of the valve  1  in the closed position. In the embodiment shown, the sleeve  14  comprises radial openings  14 ′,  14 ″ corresponding to the ports  13   a - e , such that in the open position the openings  14 ′, 14 ″ are aligned with the ports  13   a - e.    
     A fluid channel  15  extends between the main passage  11  and the annular chamber  12 . In the embodiment shown, the fluid channel  15  extends radially from the main passage  11  into a recess in the first sub  10   a , past a packer element  19  and to the chamber  12 . Through the fluid channel  15 , a pressure in the main passage  11  can be made to act on a pressure face  20  of the sleeve  14 , such as to move the sleeve from the closed position to the open position. 
     A dissolvable plug  16  is sealingly arranged in the fluid channel  15 . When in place and intact, the dissolvable plug  16  thus prevents fluid communication between the main passage  11  and the chamber  12  and thus also the pressure face  20  of the sleeve  14 . Suitable seals  21   a,b  are provided for this purpose. The dissolvable plug  16  is made from a degradable material which is reactive to water or well fluids. Well fluids may be, for example, water, hydrocarbons in liquid or gaseous form, drilling mud, etc. The degradable material may be, for example, an aluminium alloy, an aluminium-copper alloy, magnesium alloy or other well fluid degradable alloy. In the embodiment shown, the degradable material is AlGa. It is common in the industry to use degradable frac balls made of for instance aluminum alloys, magnesium alloys or zinc alloys that will dissolve in the well fluids. Any material currently used for such dissolvable frac balls may be relevant for use in embodiments of the present invention. The differences in metal alloy compositions is virtually unlimited and may be selected such as to provide a desired degradation speed. Non-metallic materials that dissolve in well fluids or water can also be used. 
     A protective element  17  is further arranged in the fluid channel  15 . The protective element  17  is arranged to isolate the dissolvable plug  16  from the main passage  11 . In the embodiment shown in  FIG. 1 , the protective element  17  is a plug  17  comprising glass, ceramic or a different type of brittle material. The protective plug  17  is sealingly arranged in the fluid channel  15  between the main passage  11  and the dissolvable plug  16 . Seals  22   a,b  are provided to fluidly seal between the walls defining the fluid channel  15  and the protective plug  17 . In the embodiment shown in  FIG. 1 , a part  17 ′ of the protective element  17  protrudes into the main passage  11 . The purpose of this protruding part will be described below. 
     Examples of the use of the valve  1  will now be described with reference to  FIGS. 1-5 .  FIG. 2  shows the valve  1  installed as part of a tubular  50  extending into a well  51 . During completion, cement  52  is pumped down into the tubular  50 , out through and end opening  53  of the tubular  50  and upwards in an annulus  54  between the tubular and the wellbore  51 . When a sufficient amount of cement has been provided, a wiper dart  55  (or an equivalent element) is pumped down through the tubular  50 . The wiper dart  55  may comprise a set of flexible scraper elements  56 , for example rubber elements, and a rigid tail element  57 . 
     Referring now to  FIG. 3 , which depicts the same situation as in  FIG. 2 . As the wiper dart  55  reaches the valve  1 , the tail end  57  will engage the protruding part  17 ′ of the protective plug  17 . As the protective plug  17  is made of a brittle material, it will break under the impact of the wiper dart  55  and the downwards force acting on the protruding part  17 ′. As the protective plug  17  breaks, illustrated in  FIG. 4 , the dissolvable plug  16  is exposed to the fluids in the main passage  11 , i.e. the fluids pumped down through the tubular  50 . The dissolvable plug  16  is reactive to this fluid, and starts to dissolve and disintegrate. The speed at which this happens may vary depending on the type of material used and the type(s) of fluid present in the main passage  11 , however eventually the fluid channel  15  is freed. When this happens, fluid in the main passage  11  is free to flow through the fluid channel  15  and to the chamber  12 , as illustrated by arrows  58  in  FIG. 5 . By pressurizing the tubular  50 , the pressure of the fluid in the main passage  11  will thus act on the pressure face  20  of the sleeve  14 , and drive the sleeve towards the open position. Fluid can then be pumped through the tubular  50  and out through the ports  13   a - e , as illustrated by arrows  59 , for example for fracturing the formation. 
     In an embodiment, illustrated in  FIG. 6 , the protective element is a coating  27  applied on at least a part of the dissolvable plug  16 . The coating  27  may, for example, only be applied on the side which, prior to activation, is exposed to the fluids in the main passage  11 , or, alternatively, it can be applied to the entire dissolvable plug  16 . 
     The coating or layer may be, for example, DLC (diamond-like-carbon), PVD (physical vapor deposition), EBPVD (electron beam physical vapor deposition), powder coating with thermosets and or thermoplastics, TSC (thermal spray coating), HVOF (high velocity oxy-fuel coating), shrouded plasma-arc spray coating, plasma-arc spray coating, electric-arc spray coating, flame spray coating, cold spray coating, epoxy coatings, plating including HDG (hot-dip galvanizing), mechanical plating, electro plating, non-electric plating method, all of which can be done with metals such as chromium, gold, silver, copper or other applicable metal; paints and other organic coatings, ceramic polymer coatings, nano ceramic particles or other nano particle coatings, rubber coatings, plastic coating, vapor phase corrosion inhibitor (VpCI®) technology or xylan coatings. 
     Activation of the valve  1  in this embodiment can be done by passing a rupture element down into the tubular  50 . For example, a rupture ball comprising pins or studs can be used. Alternatively, the wiper dart  55  may comprise such rupture elements. When the rupture elements engages the dissolvable plug  16 , the coating  27  is damaged and the dissolvable material is exposed to the fluids in the main passage  11 . The plug  16  thus starts to dissolve, which leads to activation of the valve  1  in a similar manner as described in relation to  FIGS. 1-5 . 
     As illustrated in  FIG. 6 , a part of the dissolvable plug  16  which comprises the coating  27  may protrude into the main passage  11 . This may ease the activation of the valve  1  with a rupture element. Alternatively, the coating can be damaged by other means, such as a dedicated tool therefor. The protective coating can also be of a type that is for instance removed or damaged by abrasion from the cement pumped past the dissolvable plug. In that way, the plug can, for example, be mounted flush with the inner walls of the valve  1 . 
     In an embodiment, illustrated in  FIG. 7 , the protective element is a protective cover  37  covering at least a part of the dissolvable plug  16 . The cover  37  may, for example, be applied to cover the front of the dissolvable plug  16 . The protective cover  37  may be, for example, a material comprising rubber, plastic, glass, ceramics or another type of material. 
     Activation of the valve may be done in a similar manner as described above, with a rupture element, or with a dedicated tool therefor, to damage, remove or destroy the protective cover  37  and start dissolving of the plug  16 . 
     In certain embodiments the protective element  17 ,  27 ,  37  thus need not protrude into the main passage. In such an case, the protective element  17 ,  27 ,  37  may be removed and/or ruptured by a dedicated tool. This may, for example, be a tool lowered into the tubular by wireline operation. In this case, the risk that the protective element  17 ,  27 ,  37  is accidentally ruptured or removed prior to the desired activation time is reduced. 
     In an embodiment, illustrated in  FIG. 8 , the valve  1  comprises a breakable fluid barrier  60  arranged in the fluid channel  15  and a dissolvable plug  16  also arranged in the fluid channel  15 . The breakable fluid barrier  60  is arranged between the dissolvable plug  16  and the annular chamber  12 , and may be, for example, a rupture disc made for example of glass or another brittle material, a check valve, a pressure relief valve, or any other element capable of being opened, ruptured or removed under the influence of fluid pressure. 
     In the embodiment shown in  FIG. 8 , the dissolvable plug  16  does not have a protective element. This will lead to the plug  16  starting to dissolve as soon as it comes into contact with fluids in the main passage  11  to which the dissolvable material is reactive. Nevertheless, this may be sufficient in certain applications, still providing sufficient time for, for example, pressure testing of the completion while the dissolvable plug  16  is still intact, and before activation of the valve  1 . 
     Alternatively, the dissolvable plug  16  may be arranged with a protective element according to one of the embodiments described above, or of a different type. 
     By having a breakable fluid barrier  60 , the activation of the valve  1  can be better controlled, in that a minimum pressure is required to be applied to the tubular  50  before the valve  1  is activated. By means of the dissolvable plug  16 , the pressure setting (for breakage) of the dissolvable plug  16  can be lower than the completion test pressure, thereby allowing pressure testing of the well to a high pressure while subsequently allowing pressure-induced activation of the valve without compromising well integrity. 
     In an embodiment, shown in  FIG. 9 , the valve body  10  is made up of a first sub  10   a  defining a first part of the throughbore  11 , a second sub  10   b  defining a second part of the throughbore  11 , and a housing  10   c  mechanically connecting the first sub  10   a  and the second sub  10   b . The valve  1  shown in  FIG. 9  is otherwise equivalent to that shown in  FIG. 1 , however any of the embodiments described herein may be arranged with a valve body  10  having a first sub  10   a , a second sub  10   b  and a housing  10   c  equivalent to that shown in  FIG. 9 . 
     At least two of the first sub  10   a , the second sub  10   b  and the housing  10   c  define the annular chamber  12  between them, in which the sleeve  14  is arranged. The valve ports  13   a - e  extend radially through the housing  10   c  and through at least one of the first sub  10   a  and the second sub  10   b.    
     In the embodiment shown in  FIG. 9 , the first sub  10   a  has a protruding portion  70  at a part of the first sub  10   a  which is opposite the end section  1   a . Similarly, the second sub  10   b  has a protruding portion  71  at a part of the second sub  10   b  which is opposite the end section  1   b . Connection means  72 , 73 , for example a threaded portion, is provided at an outer circumference of each protruding portion  70 , 71 . 
     The housing  1   c  in this embodiment is generally of an elongate, hollow cylindrical form and near its upper and lower ends the housing  1   c  has connection means at its inner circumference to cooperate with the connection means  72 , 73 . In the embodiment shown, threaded connections connect the first sub  10   a  to the upper end of the housing  10   c  and the second sub  10   b  to the lower end of the housing  10   c.    
     In an embodiment, illustrated in  FIG. 10 , the valve  1  comprises a breakable fluid barrier  60  arranged in the fluid channel  15  and a dissolvable plug  16  also arranged in the fluid channel  15 . The dissolvable plug  16  is arranged between the breakable fluid barrier  60  and the annular chamber  12 . As described in relation to the embodiments described above, the breakable fluid barrier  60  may, for example, be a rupture disc, a check valve, or a pressure relief valve. 
     In the embodiment shown in  FIG. 10 , the dissolvable plug  16  will be protected from the fluids in the main passage  11  until the breakable fluid barrier  60  is removed. (For example, by rupturing it by means of pressurizing the main channel  11  with a fluid pressure higher than the rupture pressure of the breakable fluid barrier  60 .) 
     The pressure at which the breakable fluid barrier  60  is configured to break or open may be lower than a test pressure applied to test the completion. In this embodiment, it is for example possible to complete the well, including running the tubular and cementing it, and returning at a later time to activate the valve  1  to prepare for/commence production. (Which may, for example, include fracturing the formation.) Pressure testing the completion will then break the breakable fluid barrier  60 , however the dissolvable plug  16  will prevent the valve  1  from activating until the plug  16  has dissolved. This thereby provides time for pressure testing without the valve  1  opening. Subsequently, when the dissolvable plug  16  has dissolved and freed the fluid channel  15 , the tubular  50  and thereby the main passage  11  can be pressurized to move the sleeve  14  and open the valve  1 . 
     Optionally, the valve  1  may comprise a second breakable fluid barrier  61 , also shown in  FIG. 10 . The second breakable fluid barrier  61  is arranged between the dissolvable plug  16  and the annular chamber  12 . The second breakable fluid barrier  61  may be configured to break at a lower pressure than the first breakable fluid barrier  60 . In this embodiment, the well may be completed and the completion be pressure tested, resulting in the first breakable fluid barrier  60  opening. The dissolvable plug  16  will, however, block the fluid channel  15  during the pressure testing of the completion. Subsequently, when the dissolvable plug  16  has freed the fluid channel  15 , the tubular  50  and thus the main passage  11  can be pressurized up to a pressure required to break the second breakable fluid barrier  61 , whereby the valve  1  can be opened. This embodiment may be advantageous, for example, if a there is a prolonged time period between the well completion/testing and the desired activation of the valve  1  and commencement of production from the well. In this time period, the fluid channel  15  will thus be blocked by the second breakable fluid barrier  61 . The dissolvable plug  16  will in such cases prevent the valve  1  from opening prematurely during the initial pressure test of the well by protecting the second fluid barrier  61  from seeing the initial test pressure. The tubing can thereby be pressure tested to the full working pressure without the risk of opening the valve  1  prematurely, and the risk of overpressuring the tubing, casing or well completion is minimized. 
     In an embodiment there is provided a downhole tool  1  having a body  10 ; an activation element  12 , 14  arranged within the body  10 ; a fluid channel  15 , 15   a,b  extending from an opening  15 ′, 15   a ′, 15   b ′ in the body  10  to the activation element  12 , 14 ; at least one dissolvable plug  16 , 16   a - c  sealingly arranged in the fluid channel  15 ; and at least one breakable fluid barrier  60 , 60   a - c  sealingly arranged in the fluid channel  15 . 
       FIG. 10  illustrates a tool  1  according to this embodiment, in this case being a valve  1 , however the tool  1  may be any type of downhole tool.  FIG. 11  illustrates, schematically, certain aspects of alternative embodiments of the tool  1 . 
     In a tool according to an embodiment, using, for example, one or more burst discs  60   a - e  and one or more dissolvable plugs  16   a - c  in the fluid channel  15 , the tool can effectively be set up with a “counter system”. By using several dissolvable plugs sandwiched between breakable fluid barriers in a row, the tool can be set up to require a given number of pressure cycles before it activates. For example, with reference to  FIG. 11( a ) , having a first breakable fluid barrier  60   a  in the fluid channel  15   a , followed by a dissolvable plug  16   a , followed again by a second breakable fluid barrier  60   b  effectively provides a two-pressure-cycle counter system: during the first pressure cycle the first breakable element is ruptured, but the activation element  14   a  is not pressurized and the tool is not activated due to the plug  16   a . However, subsequent to the barrier  60   a  being ruptured, the plug  16   a  is exposed to well fluids and starts to dissolve. When the plug  16   a  has freed the fluid path between the opening  15 ′ and the second breakable fluid barrier  60   b , the well can again be pressurized (in a second pressure cycle) to break the barrier  60   b  and activate the tool via the activation element  14   a.    
     Similarly, as shown in  FIG. 11( b ) , one can arrange three breakable fluid barriers  60   c - e  and two dissolvable plugs  16   b,c  in a channel  15   b  of a second tool, whereby the second tool then requires three pressure cycles to activate via the activation element  14   b . Consequently, according to this embodiment, downhole tools can be arranged with different configurations of fluid barriers and plugs such as to activate at different times. This can, for example, be used where different tools arranged in a well completion is to be activated sequentially at different times, where pressurizing the well in cycles from the surface will activate different tools at different times, allowing time for the dissolvable plug(s) to dissolve between the applied pressure cycles. This may include, for example, a series of valves, such as hydraulic fracturing valves, arranged in the tubing string  50 . 
     The activation element may comprise a sleeve  14  slidably arranged in a chamber  12 , as illustrated in relation to the valve  1  described above, or the activation element may be of a different type, for example a different type of mechanical activation element, a swellable element or the like. 
     According to this embodiment, such a “counter system” functionality for controlled activation of downhole tools can be obtained without any mechanical or electronic counter system and with no moving parts required to be engaged by, for example, an activation element passed down into the well. A tool according to this embodiment can thereby provide a less costly system which is less prone to breakdown or failure, for example jamming due to contamination from well fluids. 
     Examples of downhole tools that can be operated with this type of counter system include, but are not limited to: valves; production packers; downhole barrier plugs; sliding sleeves; cementing equipment; perforation systems; and setting tools. These are only examples of tools, and not meant to be limiting in any way; the skilled person will understand that this counter system can be implemented in virtually any type of downhole tool which requires activation from surface. 
     In an embodiment, there is provided a tubular assembly  50  for use in a wellbore, comprising a first downhole tool according to any of the embodiments described above and a second downhole tool according to any of the embodiments described above, wherein the first downhole tool has a higher number of dissolvable plugs  16 , 16   a - c  and a higher number of breakable fluid barriers  60 , 60   a - e  than the second downhole tool. The first downhole tool and the second downhole tool may be valves according to any of the embodiments described above. 
     According to certain embodiments described herein, an improved downhole tool is provided. In some embodiments, for example, after cementing and completion, a tool according to embodiments described here may allow more flexibility in pressure testing of the completion before the tool is activated and, for example, hydraulic fracturing operations and well production commence. Testing with high pressures may therefore be performed, without the risk that the tool unintentionally activates under the test pressure. Further, there will be no need to apply a pressure higher than that against which the completion has been pressure tested to activate the tool. 
     The tool according to certain embodiments described herein further provdes a compact and reliable solution for use as, for example, a toe valve in well completions. The inner diameter in the main passage  11  can be designed to be only minimally smaller than the tubular bore, and the risk that the operation of the valve is interrupted by, for example, cement clogging fluid activation paths is minimised. In certain embodiments there is provided a valve  1  in which the valve body  10  can be made up of fewer components with less machining required, which, for example, eases manufacturing and increases operational reliability. For example, fewer sealing faces reduces the sealing requirements and the risk of leakage, while the structural arrangement reduces the risk of operational failures, for example when the valve  1  is subjected to high compression, tension, or bending forces, as is commonly the case in wellbore completions. 
     When used in this specification and claims, the terms “comprises” and “comprising” and variations thereof mean that the specified features, steps or integers are included. The terms are not to be interpreted to exclude the presence of other features, steps or components. 
     The features disclosed in the foregoing description, or the following claims, or the accompanying drawings, expressed in their specific forms or in terms of a means for performing the disclosed function, or a method or process for attaining the disclosed result, as appropriate, may, separately, or in any combination of such features, be utilised for realising the invention in diverse forms thereof. In particular, a variety of features associated with a downhole valve  1  have been described in relation to different embodiments. Although individual fetaures may have been described in relation to different embodiments, it is to be understood that each individual feature, or a selection of features, described above may be used or combined with any of the embodiments, to the extent that this is technically feasible. 
     The present invention is not limited to the embodiments described herein; reference should be had to the appended claims.