Patent Application
20200199956
In the drilling and completion industry, it is often desirable to isolate one portion of a well bore from another. In some cases, each portion of the well bore may be treated in order to stimulate production. Various tools may be used to operate sleeves disposed along a tubing string extending into the wellbore. For example, a drop ball may be introduced into a drill string to shift a sleeve and expose stimulation ports. Another drop ball may be introduced to shift another sleeve closing the stimulation ports and opening production ports.
Prior to initiating production, it is desirable to remove the drop balls from the tubing string. There are a number of techniques for removing drop balls. A tool may be run into the wellbore from a surface system to drill out the drop balls; the drop balls may be forced through corresponding ball seats by pressure introduced from the surface system. The use of tools is a time consuming and expensive undertaking. The use of pressure is also time consuming. Drop balls may also be allowed to degrade. Specifically, drop balls may be made from a material designed to degrade when exposed to selected environmental factors.
It may be desirable to accelerate degradation of the drop balls. In such a case, an accelerant may be introduced into the tubular string to speed up degradation of the drop balls. The accelerant, typically a fluid having selected properties, is introduced into the tubular string and pumped down to the top most drop ball. Given the presence of fluid already in the tubular string, a large amount of accelerant is required to be introduced. The large amount of accelerant increases a likelihood that some of the accelerant will contact and react with the drop ball. This process is repeated for each drop ball until the tubular string is free of obstruction. Introducing an accelerant in this manner is a time consuming and expensive undertaking. Therefore, the industry would be receptive to more effective methods for removing drop balls.
Disclosed is a method of treating and producing formation fluids from a formation includes introducing a first drop ball into a string of tubulars, pumping the first drop ball to a first ball seat, applying pressure to the first drop ball to shift a first sleeve exposing an outlet port, introducing a second drop ball into the string of tubulars, pumping the second drop ball to a second ball seat, applying pressure to the second drop ball to shift a second sleeve closing the outlet port and opening an inlet port, and introducing a fluid through at least one of a first injection port directly onto the first drop ball and a second injection port directly onto the second drop ball. The first injection port is arranged upwardly of the first sleeve and fluidically connected to the first ball seat and the second injection port is arranged upwardly of the second sleeve and fluidically connected to the second ball seat. The first and second injection ports are fluidically connectable to a fluid conduit arranged externally of the string of tubulars.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures.
A resource exploration and recovery system, in accordance with an exemplary embodiment, is indicated generally at 2, in
Second system 6 may include a tubular string 20 formed from a plurality of tubulars, one of which is indicated at 21 that is extended into a wellbore 24 formed in formation 26. Wellbore 24 includes an annular wall 28. Tubular string 20 may include a ball activated treatment and production system 40 arranged in a tubular 41 coupled to Tubular string 20 between a first packer 42 and a second packer 44. First and second packers 42 and 44 define a treatment and production zone 46 along wellbore 24. It should be understood that first packer 42 and/or second packers 44 may be arranged on tubular 41 together with ball activated treatment and production system 40 or may be arranged on other ones of tubulars 21. Ball activated treatment and production system 40 includes a first sleeve 48 slideably arranged within tubular 41 and a second sleeve 50 arranged upwardly relative to first sleeve 48. Second sleeve 50 is also slideably arranged in tubular 41.
Reference will now follow to
First sleeve 48 may be shifted from a first position (
In accordance with an aspect of an exemplary embodiment, ball activated treatment and production system 40 includes a first fluid injection port 86 arranged at first sleeve 48 and a second fluid injection port 88 arranged at second sleeve 50. First fluid injection port 86 is arranged upwardly relative to first ball seat 60 when first sleeve 48 is in the open configuration such as shown in
First and second fluid injection ports 86 and 88 are fluidically connected to a fluid conduit 94 that extends to surface system 4. Fluid conduit 94 is arranged externally to tubular 41 and passes through at least first packer 44. Fluid conduit 94 may also extend toward a tow of well bore 24 (not separately labeled) through second packer 44 connecting to additional treatment and production zones (also not separately labeled).
In accordance with an exemplary aspect, a first drop ball 98 may be introduced into tubular string 20 and pumped down to first ball seat 60. Additional pressure may be applied to shift first sleeve 48 to the open configuration to start treatment of formation 26. When it is desired to initiate production, a second drop ball 100 is introduced into tubular string 20 and pumped down to second ball seat 62. Additional pressure may be applied to shift second sleeve 50 to the open configuration.
Prior to initiating production, it is desirable to remove first and second drop balls 98 and 100 from corresponding ones of first and second ball seats 60 and 62. In accordance with an exemplary aspect, first and second drop balls 98 and 100 are formed from a degradable material configured to react and degrade when exposed to a selected fluid. The particular type of fluid may vary. The selected fluid may be introduced into fluid conduit 94 and directed through first and second fluid injection ports 86 and 88 onto first and second drop balls 98 and 100. By providing the selected fluid directly to first and second drop balls 98 and 100, time needed for degradation may be greatly reduced. That is, instead of introducing a selected fluid into tubular string 20 at surface system 4, the selected fluid may be introduced directly into ball activated treatment and production system 40 to accelerate degradation and enable production.
Set forth below are some embodiments of the foregoing disclosure:
Embodiment 1. A method of treating and producing formation fluids from a formation comprising: introducing a first drop ball into a string of tubulars; pumping the first drop ball to a first ball seat; applying pressure to the first drop ball to shift a first sleeve exposing an outlet port; introducing a second drop ball into the string of tubulars; pumping the second drop ball to a second ball seat; applying pressure to the second drop ball to shift a second sleeve closing the outlet port and opening an inlet port; and introducing a fluid through at least one of a first injection port directly onto the first drop ball and a second injection port directly onto the second drop ball, the first injection port being arranged upwardly of the first sleeve and fluidically connected to the first ball seat and the second injection port being arranged upwardly of the second sleeve and fluidically connected to the second ball seat, the first and second injection ports being fluidically connectable to a fluid conduit arranged externally of the string of tubulars.
Embodiment 2. The method according to any prior embodiment, further comprising: selectively controlling the first and second injection ports.
Embodiment 3. The method according to any prior embodiment, wherein introducing the fluid includes introducing a fluid selected to accelerated degradation of the at least one of the first and second drop balls.
Embodiment 4. The method according to any prior embodiment, further comprising: treating the formation through the outlet port and producing formation fluids through the inlet port.
Embodiment 5. The method according to any prior embodiment, wherein opening the inlet port includes exposing an inflow control device to a fluid flow.
Embodiment 6. The method according to any prior embodiment, further comprising: passing a flow of fluid through a screen assembly into the inlet port.
Embodiment 7. The method according to any prior embodiment, wherein introducing the fluid into the first injection port includes opening a selectively controllable valve.
The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should further be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier “about” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity).
The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.
While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited.
This application is a divisional of U.S. application Ser. No. 15/679,489 filed Aug. 17, 2017, the disclosure of which is incorporated by reference herein in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 15679489 | Aug 2017 | US |
| Child | 16807883 | US |
