BACKGROUND OF INVENTION
In the oil and gas completions industry, a tubular string position within the wellbore will have various devices (often generically called “valves”) for controlling the flow of fluid between the interior and exterior of the tubular string. One common form for such valves is a “sliding sleeve” valve, where an outer tubular member has a series of apertures and a concentric internal tubular sleeve is shifted to uncover the apertures (i.e., “open” the valve) or to cover the apertures (i.e., “close” the valve). Often, this sleeve is shifted between its open and closed position by a tool which is run into the wellbore (e.g., on coiled tubing) and which engages a profile on the internal surface of the sleeve.
Obviously, each trip running a tool in and out of the wellbore is a time consuming and costly action. Therefore, the oil and gas industry is always seeking more efficient ways to selectively open communication between the interior of the tubular string and the producing formation through which the wellbore extends.
BRIEF DESCRIPTION OF DRAWINGS
FIG. 1 is a cross-section of a first embodiment of a flow control device of the present invention.
FIG. 2 is a cross-section of a second embodiment of a flow control device of the present invention.
FIG. 3A illustrates a first method of employing the flow control device described herein.
FIG. 3B illustrates a second method of employing the flow control device described herein.
DETAILED DESCRIPTION OF SELECTED EMBODIMENTS
The embodiment of the flow control device 1 seen in FIG. 1 is generally formed of a tubular housing 3 having a circumferential wall 5 and a central passage 4. Typically, each end of the housing will include a connector device 7, e.g., threaded or some other coupling structure, to allow the flow control device (usually a series of flow control devices) to be integrated at the appropriate location(s) along the length of the tubular string being positioned in the wellbore. The circumferential wall 5 will include a section 6 with at least one, and more commonly a plurality of, flow apertures 10 formed through the circumferential wall 5. In FIG. 1, the flow apertures 10 are a series of circular flow apertures 11 which are about 1 inch in diameter. Naturally, the size of the circular apertures 11 could vary substantially and be shapes other than circles. Section B-B seen in FIG. 1 is a cross-section through the apertures 11. In the FIG. 1 embodiment, the section 6 having the flow apertures 10 is a separable sub-component 9 connected the rest of housing 1 by threaded connection 13.
FIG. 1 suggests how the apertures 11 will be filled with a “disappearing” or dissolving material 34. Although FIG. 1 illustrates only a few apertures 11 filled with dissolving material 34, it will be understood that typically all, or substantially all, of the apertures 11 will be filled with dissolving material 34. A “dissolving” material can be any material which may initially act to plug apertures 11 under initially encountered wellbore conditions (e.g., pressure, temperature, pH, etc.), but will dissolve, degrade, or disintegrate under a second condition(s) (including extended time under initially existing wellbore conditions) to the point that fluid flow may be established through the apertures 11. As a nonlimiting example, the dissolving material should be capable of maintaining its integrity (i.e., blocking flow) at differential pressures of up to twelve thousand psi.
The dissolving material may be any number of materials including, but not limited to, dissolvable metals such as magnesium, aluminum (including alloys thereof), dissolvable polymeric materials, or other dissolvable polymers. Magnesium (Mg), either in elemental form or as an alloy, can serve as one preferred base material for dissolvable material 34. For example, the dissolvable material 34 could be Mg alloys that combine other electrochemically active metals, including binary Mg—Zn, Mg—Al and Mg—Mn alloys, as well as tertiary Mg—Zn—Y and Mg—Al—X alloys, where X includes Zn, Mn, Si, Ca or Y, or a combination thereof. These Mg—Al—X alloys may include, by weight, up to about 85% Mg, up to about 15% Al and up to about 5% X. These electrochemically active metals, including Mg, Al, Mn or Zn, or combinations thereof, may also include a rare earth element or combination of rare earth elements. As used herein, rare earth elements include Sc, Y, La, Ce, Pr, Nd, Fe, or Er, or a combination thereof. Where present, a rare earth element or combinations of rare earth elements may be present, by weight, in an amount of about 5% or less. As a specific example, TervAlloy™ available from Terves, Inc. of Euclid, Ohio is a magnesium and aluminum nanocomposite disintegrating material designed to disintegrate (turn to powder) based on exposure to a controlled fluid (e.g., an electrolyte), or an electrical or thermal stimuli. TervAlloy™ will disintegrate into very fine grained particles after a specified time in response to a controlled environmental stimulus. A wide range of solvents may be employed as long as they are capable of reducing the dissolving material without excessive corrosion of downhole tubulars and equipment. As nonlimiting examples, the solvent could be brines formed from NaCl, CaCl, NaBr, CaBr, caesium formates, sodium formates, etc. Likewise, the solvent could be any number of acids including various concentrations of hydrofluoric acid, hydrochloric acid, sulfuric acid, acetic acid, and other acids commonly used in the downhole environment. In one embodiment, the dissolvable material such as the above TervAlloy™ may be coated with a polymer that is unaffected by acids and brines found in the downhole environment where the material is to be used. When it is desired to remove the dissolvable material, a solvent effective against the polymer (e.g., hydrofluoric acid) is circulated to remove the polymer coating, thus exposing the TervAlloy™ existing brines that will ultimately degrade it. The brine may be latent brine or additional brine which is circulated downhole.
Adjacent to the section 6 of apertures 10 is the closing sleeve 20. Closing sleeve 20 is a slidable sleeve having an outer diameter slightly smaller than the inner diameter of section 6 such that closing sleeve 20 travels into section 6. Although a portion of the sleeve length is shown removed in the FIG. 1 illustration, the length of closing sleeve 20 will be sufficient to engage the sleeve seals 30A and 30B on each side of section 6. In the illustrated embodiment, closing sleeve 20 will include a tool profile 26 allowing a conventional closing tool (e.g., a tool mounted on coil tubing or wireline) to engage the tool profile 26 and apply the force necessary to move closing sleeve 20 into the section 6. Closing sleeve 20 will also include a closing collet 22 having a series of collet fingers 23. As is well known in the art, collet fingers will be biased outward, but be configured to flex inward with the application of sufficient force. In FIG. 1, the collet fingers are shown engaging the open collet profile 25, which will require a first pulling force (for example, about 3000 to 4000 lbs) to move the collet fingers out of profile 25. Although not explicitly seen in the Figures, it can be envisioned how, as closing sleeve 20 moves into its closed position blocking the apertures 11, the collet fingers 23 will move into and engage the closed collet profile 24. The closed collet profile is configured such that a similar force is required to dislodge the collet fingers 23 from closed collet profile 24. As suggested above, once closing sleeve 20 is in the closed position, the sleeve's engagement will seals 30A and 30B will form a fluid tight barrier preventing fluid communicating though the apertures 11 (i.e., in the case where the dissolvable material 34 has been dissolved from apertures 11). Although seals 30A and 30B could be any number of conventional or future developed seals, in certain examples, seals 30A and 30B may be a bonded seal or an unipack seal, e.g., a seal formed from a mesh/rubber matrix.
Although the FIG. 1 embodiment illustrates a single section 6 of flow apertures and a single closing sleeve 20 between two connector devices 7, it will be understood that other embodiments could have multiple sets of flow aperture sections 6 with closing sleeves 20 positioned sequentially as a continuous tubular section with no intervening connector devices 7. This principle applies equally to the FIG. 2 embodiment discussed below.
FIG. 2 illustrates a modification of the flow control device shown in FIG. 1. In the FIG. 2 embodiment, the flow apertures 10 are formed of elongated slots 12. However, the flow apertures in some instances may be circular, oval, or other shaped apertures. Moreover, rather than the flow apertures 10 being directly filled with the dissolvable material, the FIG. 2 embodiment utilizes an inner sleeve 35 formed of the dissolving material (or dissolving sleeve 35). In one example, dissolving sleeve 35 material is formed from the TervAlloy™ specified above. In the example of the tubular housing 3 having an outer diameter of approximately 6 inches, the thickness of dissolving sleeve 35 is approximately ⅜ inches. However, the housing dimensions and sleeve thicknesses may vary considerably among different embodiments. In the FIG. 2 embodiment, the positioning of dissolving sleeve 35 acts to block closing sleeve 20 prior to the time dissolving sleeve 35 has been dissolved. Once dissolving sleeve 35 has been removed, then closing sleeve 20 may function in conjunction with seals 30 as described in FIG. 1 with respect to blocking flow through flow slots 12. FIG. 2 also shows a profile 36 formed on the inner surface of dissolving sleeve 35. This profile is intended to aid in the tool assembly process. A gripping tool may engage profile 36 and assist in overcoming the tight tolerances encountered when inserting dissolving sleeve 35 within the tubular sections forming housing 2.
In many contemplated uses, the flow control device seen in FIGS. 1 and 2 may include well screens positioned over tubular housing 2. One such screen is represented schematically in FIG. 2 as screen section 45. Any number of convention or future developed well screens could be employed depending on wellbore conditions and the type/size of particles the screen is intended to block from entry through the flow apertures. As one non-limiting examples, the screens could be slip-on wire jackets, direct wrap wire jackets, slip-on pre-pack filters, or woven mesh filters. Example screen/filter opening sizes could be from 60 um to 500 um (or any sub-range there between). Although not explicitly shown in the drawings, many embodiments will be formed of a series of flow control devices 1 connected together under a continuous length of screen section.
As one example of a contemplated use, a tubular string incorporating a series of flow control devices 1 will be run into the wellbore such that the flow control devices are positioned at the wellbore locations where communication exterior to the string is desired. At this point, the dissolvable material is intact in the flow apertures (or the dissolving sleeves are in place) and the closing sleeves (i.e., nondissolving permanent sleeves) are in the open position. Various downhole operations requiring an increase of fluid pressure internal to the tubular string may be carried out; for example, setting pressure activated packers incorporated into the string, or circulating while running in the hole without need of an inner string. In one example, the pressure is within the central passage of the flow control device is increased in the range of about 7,500 to 15,000 about p.s.i. (or any sub-range therebetween).
It will be understood that when the dissolvable material is in place in the flow apertures, there are no flow paths through the circumferential wall of the tubular housing, i.e., no flow paths from outside the tubular housing into the central passage (or from the central passage to the outside of the tubular housing). The absence of flow paths is not only in portion of the central passage in the immediate area of the flow apertures, but also portions of the central passage extending above or below the tubular housing along the tubular string.
As suggested above, there are certain embodiments where the step of initially positioning the flow control device in the wellbore includes running the flow control device into the wellbore without a service tool (or any other type of inner tubular member) being positioned within the central passage of the flow control device's tubular housing. These embodiments could be employed to carry out operations such as a single trip standalone screen application where the production assembly and sandface assembly are run and installed in a single trip using the dissolvable material as a barrier to flow. This arrangement enables circulation of filter cake removal fluids, packer corrosion inhibitor fluids, and aides in fluid loss control while removing the BOP's and installing the wellhead. Further, packers may be set without the need of running a plug or any other isolation device by applying pressure against the dissolvable material prior to its degradation phase permitting activation of any downhole hydraulic device in the completion assembly as required.
When it is desired to establish communication outside the tubular string, a dissolving agent may be circulated into contact with the dissolving material for sufficient duration to remove or to sufficiently weaken the dissolving material within the flow apertures. For example, this may be achieved at the end of a gravel or frac pack using the inner service tool string on a multi-zone, single trip application; or it can be achieved using a smaller workstring run on a separate trip to circulate the solvent (dissolution fluid). This may involve a single solvent or more than one (e.g., one solvent to remove a protective coating and another to dissolve the underlying material) and thus involve separate trips to spot the different solvents. Once this is accomplished, fluid communication will be opened with the environment exterior to the tubular string. When the well operator desires to close off this fluid path, a closing tool is run downhole to engage and shift the closing sleeve into the closed position.
FIGS. 3A and 3B illustrate two nonlimiting examples of methods employing the above concepts. FIG. 3A shows the wellbore 100 extending through a producing interval 120 with wellbore 100 being a “cased” wellbore including casing 105 and cement layer 110. The casing and cement layer have been perforated in order to establish communication with the producing interval. A tubular string 75, including packers 60, is positioned within the producing interval 120. The packers 60 could be any number of conventional or future developed packers which operate to isolate the wellbore annulus along the producing interval. In the FIG. 3A example, packers 60 may be pressure activated packers such as CompSet™ packers available from Superior Energy Services, LLC, Completion Services division, of Houston, Tex. Between packers 60, the tubular string includes a plurality of flow controls devices 1 such as described above in reference to FIG. 1 or 2. FIG. 3A illustrates three flow control devices positioned sequentially one after the other. However, other embodiments could include other tubular sections (e.g., screen sections or joints) between the flow control devices 1.
In operation, the tubular string is lowered into the wellbore until the packers 60 are positioned above and below the producing interval. As suggested in FIG. 3A, there is no service tool, inner workstring, or other tubular member position in the central passage of the tubular string 75 as it is lowered into position. At this point, the flow apertures in the flow control devices are still plugged with the dissolvable material and any number of down hole operations may be carried out. For example, the flow arrows in FIG. 3A suggest the circulation of fluid down the central passage of the tubular string and back up the annulus, it being understood that packers 60 are unset at this stage. When it is desired to set the packers, the lower end of the tubular string (not seen in FIG. 3A) is closed off by any conventional means such as a pressure operated valve or by dropping a ball which engages a ball seat. Thereafter, fluid in the tubular string's central passage may be raised to the degree necessary to set packers 60. In order to open the flow apertures in the flow control device, the dissolvable material in the flow apertures will be dissolved, e.g., by allowing existing wellbore fluids to degrade the dissolvable material over time. In cases where it is necessary to circulate an acid or other solvent in order to remove the dissolvable material, the solvent will be circulated to or “spotted” in the area of the dissolvable plugs prior to setting the packers. Then the packers are promptly set before the solvent significantly affects the structural integrity of the plugs.
FIG. 3B shows a slightly different configuration of the tubular string. In the FIG. 3B example, the tubular string section within the production zone includes an flow control device 1 with at least one screen joint 50 above or below the flow control device. As used herein, “screen joint” means any suitable conventional or future developed screen section used in the oil and gas wells, typically formed by a section of base pipe with apertures and one or more layers of screen material overlaying the base pipe. One example of screen joint 50 could be the ProWeld TOP™ screen section available from Superior Energy Services, LLC, Completion Services division, of Houston, Tex. Naturally, the FIG. 3B embodiment is merely illustrative and other configurations could multiple screen joints above and/or below the flow control device 1 or multiple flow control devices 1 in combination with the screen joints. Since a wellbore may often be deviated or horizontal, “above” and “below” do not necessarily mean higher or lower in the vertical sense, but rather closer, along the wellbore path, to the surface or toe of the wellbore toe, respectively.
Although FIGS. 3A and 3B only illustrate one producing interval, it will be understood that there are often multiple producing intervals along the length of the wellbore. Each interval could include a flow control arrangement such as seen in the figures with the packers separately isolating each interval. Typically, the packers are set and intervals treated in succession, with operations conducted on the lowest interval first. It can readily be seen that while the dissolvable plugs are in place, the flow control tools will provide fluid loss control for fluids circulated through the tools, i.e., prevent unintended loss of fluids into the formation Likewise, while FIGS. 3A and 3B illustrate methods carried out in cased wellbores, it will be understood these methods could also be employed in uncased wellbores.
Patent Application
20160326837
