FOR HYDRAULIC FRACTURE APPLICATION

FIELD OF THE DISCLOSURE

[0001] This disclosure relates to coiled- in-coiled tubing. More particularly, this disclosure relates to systems and methods for concentric coiled-in-coiled tubing for use in treating a wellbore, and the like.

BACKGROUND

[0002] Coiled tubing has proven increasingly useful in oil and gas field applications, including workovers, drilling, logging and well stimulation. Typically, coiled tubing units comprise a continuous length of several thousand feet (possibly up to 25,000 feet) of steel tubing, capable of withstanding pressures on the order of 15,000 psi, capable of being repeatedly coiled and uncoiled from a mobile spool, and capable of being injected and withdrawn from oil and gas wells without killing the well.

[0003] Coiled tubing lengths are generally understood in the field to comprise several hundred or several thousand feet of continuous, uniform outer diameter tubing, coilable on a truckable spool and injectable in a bore by means of a coiled tubing injector. The continuous lengths are typically, although not necessarily, manufactured of steel having a longitudinally welded seam. Resin and fiber polymer materials may also be used for continuous tubing. Typically, successive lengths of steel tubing are welded to create a desired unit length. In addition, coiled tubing is expected to be able to withstand significant pressure differentials, such as at least 1,000 psi and preferably closer to 15,000 psi, and to be sufficiently corrosive resistant and heat resistant to withstand exposure to common hydrocarbons downhole. [0004] The term "truckable spool" means a spool or reel having an outside diameter of approximately six meters, and typically less, so that the spool can be transported by a boat or by a truck over land and highways to a site. Coiled tubing generally has sufficient flexibility to be reeled on a truckable spool and repeatedly coiled and uncoiled from such a spool or reel. Likewise, coiled tubing's ability to be injected in a bore means that the tubing, while flexible, is also sufficiently rigid that lengths of several hundred or thousand feet can be continuously thrust, or injected, in bores using coiled tubing injection equipment.

[0005] In addition to the applications mentioned above, coiled tubing has also been used in hydraulic fracturing applications. However, one drawback of current fracture methods is that they implement a single coil of tubing and there may be a risk of getting stuck within a wellbore due to the high frequency of screen outs that may occur during some treatment procedures, such as fracturing.

[0006] Oil and gas operations have known the use of concentric coiled-in-coiled pipe strings. Concentric pipe strings provide two non-well bore channels for fluid communication downhole, typically, with one channel, such as the inner channel, used to pump fluid (liquid or gas or multiphase fluid) downhole while a second channel, such as the annular channel formed between the concentric strings, used to return fluid to the surface.

[0007] Existing systems, however, do not implement concentric or multi-centric coiled tubing in hydraulic fracturing applications as disclosed herein.

SUMMARY

[0008] One advantage of the disclosed system and methods is they provide an efficient system and method for treating a wellbore and recovery process that enables, if required, the removal of a screen out, treatment, proppant, and/or solids in each fracture created.

[0009] One embodiment of the present disclosure is a method of treating a wellbore comprising positioning an end of a coiled tubing string adjacent a portion of a wellbore, the coiled tubing string having a first flow area, a second flow area, and a valve configured to control flow out of the first and second flow areas into the portion of the wellbore. The method comprises treating a portion of the wellbore by pumping fluid down at least one of the first and second flow areas.

[0010] The method may include pumping fluid down both the first flow area and the second flow area to treat the portion of the wellbore. The method may include isolating the portion of the wellbore prior to treating the portion of the wellbore. Isolating the portion of the wellbore may comprises setting a plurality of isolating elements. The valve may be located proximal to the end of the coiled tubing string. The method may include actuating the valve and pumping fluid up the second flow area while pumping fluid down the first flow area. The valve may permit fluid and particulates in the portion of the wellbore to flow up the second flow area. Treating the wellbore may comprise fracturing a formation adjacent the portion of the wellbore. A screen out may have formed in a fracture during the fracturing of the formation. The method may include cleaning out the screen out from the portion of the wellbore. Actuating the valve and pumping fluid up the second flow path may clean out the screen out.

[0011] One embodiment of the present disclosure is a system to treat a portion of a wellbore. The system comprises a coiled tubing string having a first flow area and a second flow area and at least one valve configured to control flow of both the first and second flow areas out of the coiled tubing string. The system may include at least one isolation element. The valve of the system may be positioned proximate an end of the coiled tubing string. The system may include at least one port that permits communication from the first flow area and an exterior of the coiled tubing string and at least one port that permits communication from the second flow area and the exterior of the coiled tubing string, wherein the at least one valve is configured to control flow out both ports. The at least one isolation element may be actuated to isolate a portion of the wellbore. Fluid may be pumped down the first and second flow areas from a surface location to treat the isolated portion of the wellbore. The valve may be actuated so that fluid may be pumped down from the surface in the first flow area and pumped up to the surface in the second flow area. A formation of the portion of the wellbore may be fractured or stimulated by pumping fluid down both the first and second flow areas. Fluid pumped up to the surface in the second flow area may be used to remove a screen out of a fracture of the portion of the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

[0012] FIG. 1 shows an embodiment of a coiled tubing string that may be used to treat a portion of a wellbore.

[0013] FIG. 2 shows an embodiment of a coiled tubing string that may be used to clear a screen out during a treatment procedure, such as a hydraulic fracturing.

[0014] FIG. 3 shows a cut away view of a coiled tubing string.

[0015] FIG. 4 shows a cross-sectional view of an embodiment of a coiled tubing string.

[0016] FIG. 5 shows a cross-sectional view of an embodiment of a coiled tubing string.

[0017] While the disclosure is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and will be described in detail herein. However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Rather, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

[0018] FIG. 1 shows a coiled tubing string 100 having a first flow path 101 and a second flow path 102 positioned within a wellbore 1. As described herein, the coiled tubing string 100 may have various configurations that permit two flow paths 101 and 102. The coiled tubing string 100 may be a coiled-in-coiled tubing string with one flow path down the inner coiled tubing string and the other flow path down the larger coiled tubing string. Alternatively, the coiled tubing string may include an internal wall that separates the interior of the coiled tubing string 100 into two separate flow paths. The coiled tubing string 100 may be used to treat a portion of a wellbore 1. Fluid may be pumped down the first flow path 101, as indicated by the arrow in FIG. 1, and out a port 111 to treat the wellbore 1. Likewise, fluid may be pumped down the second flow path 102, as indicated by the arrow in FIG. 1, and out a port 112 to treat the wellbore 1. A valve 110 may be used to control fluid flow through the flow paths 101 and 102 in the coiled tubing string 100. The valve 110 may be positioned adjacent the ports 111 and 112 may be used to control the flow of fluid between the ports 111 and 112 and the flow paths 101 and 102. Alternatively, the valve 110 configured to control the fluid flow through the two flow paths 101 and 102 may be positioned at various locations along the coiled tubing string 100 including at the surface. The configuration of the ports 111 and 112 and valve 110 with respect to the end of the tubing string 100 and each other is for illustrative purposes only and may be varied as would be appreciated by one of ordinary skill in the art having the benefit of this disclosure. [0019] The portion of the wellbore 1 may be isolated from the rest of the wellbore by upper and/or lower isolating elements 120. Various isolation elements 120 that may be connected to a coiled tubing string 100 may be used with the coiled tubing string 100 disclosed herein. For example, the coiled tubing string 100 may be connected to the tool disclosed in U.S. patent app. no. 14/318,952 entitled "Synchronic Dual Packer," filed on June 30, 2014, which is incorporated by reference herein in its entirety. The coiled tubing string 100 having two flow paths 101 and 102 with a valve 110 that may be actuated to control the flow of the flow paths 101 and 102 may be used with or without upper and lower isolation elements 120.

[0020] The coiled tubing string 100 may be used during various treatment procedures to treat a portion of a wellbore 1. For example, an acid may be delivered to a production zone to stimulate production. The coiled tubing string 100 having two flow paths 101 and 102 may also be used to fracture a formation 5 of a wellbore 1. As shown in FIG. 1, upper and lower isolation elements 120 may be actuated to isolate a portion of the wellbore 1 that includes a perforation 2 in the wellbore casing. Fluid may be pumped down either of the flow paths 101 and 102 or may be pumped down both of the first and second flow paths 101 and 102 to fracture 6 the formation 5. The coiled tubing string 100 may also be used to treat and/or fracture an open hole wellbore as would be appreciated by one of ordinary skill in the art having the benefit of this disclosure.

[0021] The portion of the wellbore being treated through the coiled tubing string 100 may require a clean out procedure. For example, during a fracturing procedure a screen out 10 may form in the fracture 6 and wellbore 1 as shown in FIG. 2. Pumping fluid down both the first and second flow paths 101 and 102 of the coiled tubing string 100 will not remove the screen out 10 as there is nowhere for the sand forming the screen out to go. To remove the screen out 10, the valve 110 of the coiled tubing string 100 may be actuated to permit fluid to be pumped down one of the flow paths, such as the first flow path 101, and to be pumped up the other flow path, such as the second flow path 102, as indicated by the arrows in FIG. 2. Fluid pumped up one of the flow paths 102 of the coiled tubing string

100 permits the removal of the sand forming the screen out 10 from the isolated portion of the wellbore 1. The coiled tubing string 100 having two flow paths 101 and 102 with at least one valve 110 that controls the flow paths 101 and 102 to function as a coiled tubing string 100 to treat a wellbore as well as conduct a cleanout procedure. The coiled tubing string 100 may include more than one valve 110 to control the flow through the flow paths

101 and 102 as would be appreciated by one of ordinary skill in the art having the benefit of this disclosure. Likewise, the fluid may be pumped down the second flow path 102 and up the first flow path 101 as would be appreciated by one of ordinary skill in the art having the benefit of this disclosure.

[0022] FIG. 3 shows a cutaway view of an embodiment of a coiled tubing string 200 having an inner coiled tubing 201 positioned within an outer coiled tubing 202. The coiled tubing string 200 includes a first flow area 203 down the interior of the inner coiled tubing 201 and a second flow area 204 between the exterior of the inner coiled tubing 202 and the interior of the outer coiled tubing 202.

[0023] FIG. 4 shows a cross-section view of an embodiment of coiled tubing string 200 having an inner coiled tubing 201 positioned within an outer coiled tubing 202. The inner coiled tubing 201 may be connected to the outer coiled tubing 202 or may be free to move within the outer coiled tubing 202. FIG. 4 shows the first flow area 203 and the second flow area 204.

[0024] FIG. 5 shows a cross section view of an embodiment of a coiled tubing string 300 having a first flow area 303 and a second flow area 304. An inner wall 302 in between the outer wall 301 of the coiled tubing string 300 divides the cross-sectional area of the coiled tubing string 300 to form the two flow areas 303 and 304.

[0025] The various configurations of a coiled tubing string 100 having a first and second flow areas 101 and 102 are for illustrative purposes only. Various configurations may be used to form a coiled tubing string 100 having two flow paths 101 and 102 that may be controlled by one or more valves 110 as would be appreciated by one of ordinary skill in the art having the benefit of this disclosure.

[0026] Although various embodiments have been shown and described, the present disclosure is not so limited and will be understood to include all such modifications and variations are would be apparent to one skilled in the art.