Abstract:
A tubular member is presented for treating a subterranean formation, the tubular member being insertable in a wellbore intersecting the subterranean formation and adapted to receive a treatment fluid under pressure. The tubular member comprises at least one assembly having at least one port; a straddle system comprising an upper packer uphole of the at least one assembly and a lower packer downhole of the at least one assembly to isolate an annular interval adjacent the ported assembly between the tubular member and the wellbore; and at least one flow diverter valve positioned uphole from the upper packer for diverting fluid from within the tubular member through an annulus between the tubular member and the wellbore to surface. Methods are further provided for treating a subteranian formation

Description:
FIELD OF THE INVENTION 
       [0001]    The present invention relates to hydraulic or mechanical completion equipment for wellbores in general, and in particular relates to equipment for circulating fluids in fracturing and stimulating subterranean formations bearing oil or gas. 
       BACKGROUND OF THE INVENTION 
       [0002]    If a hydrocarbon bearing subterranean formation either lacks permeability or flow capacity for cost effective recovery of the hydrocarbon, then it is common practice to use hydraulic fracturing or other treatment of the formation to increase the flow of the hydrocarbon, typically oil or gas. This method of stimulation creates flow channels for the hydrocarbon to escape the formation into a wellbore penetrating the formation, to maintain well production. 
         [0003]    The wellbore typically consists of a metal pipe, commonly known as a “casing”, “production casing”, “wellbore liner” or “completion string”, which is deployed into the borehole and is cemented into place. Fracturing of the formation occurs when a treatment fluid is pumped under high pressure into the casing, usually via a tubular treatment string run inside the casing, and is ejected through holes in the casing, and through the cement, into the formation to cause fractures in its strata. The treatment fluid carries a proppant, such as sand or the like, which penetrates the fractures to hold them open after the treatment fluid pressure is released, and can include additives such as acids. Alternatively, the formatting maybe treated by injection of fluids at lower pressures than fracturing, to stimulate the formation without causing fractures in the strata. 
         [0004]    In many fracking or treatment situations, a first treatment fluid is first pumped down the inner bore of the tubular treatment string and out through ported assemblies on the treatment string. The ported subs are preferably isolated from other stages of the formation by an isolation device to ensure that the first treatment fluid is directed to the desired zone of the formation to be stimulated. The isolation device seals against casing to prevent fluid from flowing into the annulus between the treatment string and the casing, and out of the isolated stage. In a next step, second treatment fluids are pumped down the well to frac or otherwise treat or stimulate the formation. 
         [0005]    When the isolated zone has been treated, flow of treatment fluids is reduced or stopped entirely and the treatment string is released and moved either uphole or downhole to the next zone to be treated. 
       SUMMARY OF THE PRESENT INVENTION 
       [0006]    A tubular member is presented for treating a subterranean formation, the tubular member being insertable in a wellbore intersecting the subterranean formation and adapted to receive a treatment fluid under pressure. The tubular member comprises at least one assembly having at least one port; a straddle system comprising an upper packer uphole of the at least one assembly and a lower packer downhole of the at least one assembly to isolate an annular interval adjacent the ported assembly between the tubular member and the wellbore; and at least one flow diverter valve positioned uphole from the upper packer for diverting fluid from within the tubular member through an annulus between the tubular member and the wellbore to surface. 
         [0007]    A method is further provided for treating a subteranian formation. The method comprises inserting a tubular member into a wellbore intersecting the subterranean formation, the tubular member being adapted to receive a treatment fluid under pressure and comprising at least one ported assembly and one or more flow diverter valves positioned uphole of said ported assembly; setting an isolation device in an annulus between the tubular member and the wellbore for hydraulically isolating intervals in the annulus at locations adjacent the at least one ported assembly; flowing a first treatment fluid under pressure into the at least one isolated ported assembly to treat the formation in the isolated interval of the wellbore by pressurized treatment fluid flowing from the ported assembly; opening one or more flow diverter valves positioned uphole of the isolated assembly; and diverting the first treatment fluid from within the tubular member through the flow diverter valve, through the annulus to surface. 
         [0008]    A further method is provided for treating a subteranian formation, the method comprising: inserting a tubular member into a wellbore intersecting the subterranean formation, the tubular member being adapted to receive a treatment fluid under pressure and comprising plurality of ported assemblies spaced at intervals along a length of the tubular member and one or more flow diverter valves positioned uphole of each of said ported assemblies; setting an isolation device to hydraulically isolate a first at least one interval in the annulus, said first at least one interval having at least one first ported assembly positioned therein; flowing treatment fluid under pressure through the first ported assembly and allowing treatment of the formation in the first isolated interval of the wellbore by the pressurized treatment fluid; releasing treatment fluid pressure; and repeating the steps of: i. opening one or more flow diverter valves positioned uphole of the isolated interval; ii. diverting treatment fluid from within the tubular member through the one or more flow diverter valves into the annulus uphole of the isolated interval, to equalize annular pressure above the isolated interval with annular pressure within the isolated interval; iii. initiating movement of tubular member to a subsequent interval of the wellbore, said subsequent interval comprising at least one subsequent ported assembly; iv. setting the isolation device to hydraulically isolate the subsequent at least one interval in the annulus; v. flowing treatment fluid under pressure through the at least one subsequent ported assembly to the formation in the isolated subsequent intervals of the wellbore by the pressurized treatment fluid; and vi. releasing treatment fluid pressure. 
         [0009]    A method is further provided for treating one or more isolated intervals of a subteranian formation. The method comprises flowing treatment fluid under pressure through a first ported assembly on a tubular member and allowing treatment of the formation in a first isolated interval by the pressurized treatment fluid; moving the tubular member to a subsequent interval of the wellbore, said subsequent interval comprising at least one subsequent ported assembly; and simulataneously circulating treatment fluid from within the tubular member through one or more flow diverter valves into an annulus uphole of the first isolated interval while moving the tubular member. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWING FIGURES 
         [0010]    Embodiments of the invention will now be described, by way of example only, with reference to the accompanying drawings, wherein: 
           [0011]      FIGS. 1 a  to 1 m    illustrate in cross-section an environment and a method of fracing or treating a formation using a treatment string within a production casing according to an embodiment of the present invention; 
           [0012]      FIG. 2  is an elevation view of a treatment string with a ported assembly and a flow diverter valve of the present invention; and 
           [0013]      FIG. 3  is a process diagram illustrating a first method of the present invention; 
           [0014]      FIG. 4  is a process diagram illustrating a second method of the present invention; and 
           [0015]      FIG. 5  is a process diagram illustrating a third method of the present invention. 
       
    
    
     DESCRIPTION OF PREFERRED EMBODIMENTS 
       [0016]    Although the device and method of the present invention may be employed for various types of wells and completion procedures, such as with open hole packers in an uncemented well, a horizontal cemented well will be referred to herein for illustrative purposes. 
         [0017]    With reference to  FIGS. 1 a  to 1 m   , a production casing  16 , also known as a completion string or wellbore liner, is inserted, or tripped, into the wellbore  10  to its terminus  11 . An annular space  18 , or annulus, is formed between the casing  16  and the wall of the wellbore  10 . The production casing  16  may be considered a tubular member capable of flowing or communicating fluids under pressure along the wellbore. 
         [0018]    Assemblies  20  are employed to join segments  17  of the production casing. Alternately, if no pipe segments are to be employed and the assemblies  20  are to be joined directly, then the assemblies  20  may have cooperative thread patterns, or alternate joining means. 
         [0019]    The assemblies are preferably ported assemblies  20  having one or more ports  28 . In some cases, the assemblies  20  are of the form of a “burstable disk”, also known as a “rupture disk” or “burst disk”. The disk has a rupture pressure threshold, and is located to block the flow of fluids through the hole while intact. Once the treatment fluid pressure reaches this threshold, the disk bursts to allow the treatment fluid to escape through the casing hole and fracture the formation strata. 
         [0020]    Alternatively, some ported assemblies  20  provide a means of sealing a port  28  in a completion string from fluid flow therethrough when the insert is intact. 
         [0021]    Further alternatively, the ported assemblies  20  may have shiftable sleeves that can be opened and closed by any number of means including, but not limited to hydraulic pressure acting on the sleeve or by mechanical actuation of an intervention tool that is deployed by coiled tubing, wireline or other means downhole to engage and move the sleeve to open the port  28 . 
         [0022]    A method of sequential fluid treatment of multiple intervals with a tubular member in a wellbore is now described. Cement is pumped down the production casing  16  and through each of the ported assemblies  20 . The cement continues to be pumped until it exits the production casing near the wellbore terminus  11  and begins to fill the annulus  18 , including around the collars  20  ( FIG. 1 e   ). Pumping of the cement is accomplished with a tubular pumping member  112  that pushes the cement down the production casing until it reaches the terminus  11 , at which point the cement has been largely evacuated from the production casing into the annulus past each of the ported assemblies  20  ( FIG. 1 f   ). The operator can then slightly pressure-up the casing string to ensure all of the cement has been evacuated from the casing, sometimes referred to as “bumping up the wiper plug”. Once the cement sets to securely bond the production casing in the wellbore, the well is ready to be completed. 
         [0023]    Completion of the well requires, in this example, a coil fracturing or treatment system where a tubular member preferably in the form of a treatment string  114  is tripped down the production casing  16  ( FIG. 1 g   ). The treatment string  114  is located so as to position an isolation device  106  in a manner which fluidly isolates a given interval  116  of the production casing. 
         [0024]    Preferably a packer/cup or cup/cup type straddle system  106  is employed as the isolation device to isolate a first ported assembly  20   a , referred to herein as the first stage. A treatment fluid is then injected under pressure into the isolated interval  116  of the ported assembly. When a threshold pressure is reached, the treatment fluid exits through the first ported assembly  20   a  to initiate the fracing or other treatment process. The fracing or treatment process continues in the vicinity of the first ported assembly  20   a  as the pressurized treatment fluid (indicated by  119  in  FIG. 1 i   ) exits the ports  28  and through the initial cracks to propagate further cracking  120  or to treat or stimulate the formation. 
         [0025]    Once the fracing or treating process is completed for the first stage, the pressure on the treatment fluid is released and the treatment string is moved back to create a further isolated interval  120  straddling the a subsequent ported assembly  20   b  ( FIG. 1 j   ), and the above fracing or treating process is followed for this second stage. This process is repeated for each stage ( FIG. 1 k   ) until the last stage ( 20   f  in  FIG. 1L ) is completed and the treatment string is rigged out. The well is then ready for production by flowing the target fluid ( 14  in  FIG. 1 m   ) from the formation through the many ports and up the production casing to surface. 
         [0026]    A further preferred embodiment of the invention is illustrated in  FIG. 2 . In many fracking or stimulation situations, a first treatment fluid such as water is first pumped down the inner bore of the production string  114  and out through ported assemblies  20 . The ported assemblies  20  are preferably isolated from other stages of the formation by an isolation device  106 , preferably in the form of a cup/packer or cup/cup type straddle system  106 , comprising an upper packer  106   a  uphole of the ported assembly  20  and a lower packer  106   b  downhole of the ported assembly  20 , to ensure that the first treatment fluid is directed to the isolated stage  116  of the formation to be stimulated. The straddle system  106  seals against casing  16  to prevent fluid from flowing into the annulus  18  outside of the isolated stage  116 . In a next step, a second treatment fluid, optionally sand followed by a fracking slurry, is pumped down the well to frac the formation. Alternatively, the second treatment fluid may be a non-fracking second stimulant. 
         [0027]    The pumping of the second treatment fluid acts to displace the first treatment fluid, typically water, in the inner bore and dispel the first treatment fluid through the ported assembly  20  and into the formation. Since most treatment strings  114  can be several kilometers long, a significant amount of first treatment fluid is standing in the inner bore that must be displaced into the formation by the sand. This first fluid is essentially wasted. 
         [0028]    To reduce and prevent wastage, the present invention provides one or more flow diverter valves  110  positioned uphole from the ported assembly  20  and the straddle system  106 , that serve to divert the first treatment fluid standing in the inner bore of the production string  114  back up through the annulus  18  to surface where it can be collected and reused. The method is illustrated in  FIG. 3 . 
         [0029]    In further embodiments, as illustrated in  FIGS. 4 and 5 , the present flow diverter valve  110  serves to recycle water or other treatment fluids standing in inside the treatment string  114  out to surface when the treatment string  114  is moved from one interval to be treated, to a subsequent interval. 
         [0030]    By diverting treatment fluid into annulus  18  above upper packer  106   a , fluid pressure above the isolated stage  116  is equalized with pressure experienced below the upper packer  106   a , to release the packer  106   a  so that the treatment string  114  can be moved. 
         [0031]    A similar pressure equalizing can be created on either side of lower packer  106   b , by means of a bypass valve  200  located downhole of lower packer  106   b  and which can be opened to allow treatment fluid circulation downhole of lower packer  106   b , to release lower packer  106   b  and allow the treatment string  114  to move to the next interval. By equalizing pressure on either side of the straddle system  106 , the straddle system  106  experiences less wear as it is moved with the treatment string  114  from interval to interval. 
         [0032]    Circulating fluids through the flow diverter valve  110  simultaneously while moving the treatment string  114  between intervals saves significant time from traditional methods in which fluid flow must be completely stopped when moving between intervals, and then started up again. 
         [0033]    Fluid pressure created by the flow diverter valve  110  further serves to maintaining sufficient pressure in the annulus  18  at surface to prevent fluid from the treated interval from migrating past the upper packer  106   a  and up towards surface. 
         [0034]    Opening of the bypass valve  200  advantageously serves to minimize swabbing effects that result when bottom hole pressure, that is pressure of the formation below the first isolated interval  116 , is reduced below the formation pressure due to the effects of pulling the treatment string  114  uphole from one interval to the next. This pressure reduction can detrimentally allow for an influx of formation fluids into the wellbore. By opening bypass valve  200 , treatment fluid can be directed downhole of lower packer  106   b  to equalize pressure and maintain bottom hole pressure at or above formation pressure to prevent ingress of formation fluids in to the wellbore from the bottom. 
         [0035]    With further reference to  FIG. 2 , each of the present flow diverter valves  110  is preferably comprised of an inner sleeve  109  and an outer sleeve  108 . Each of the inner sleeve  109  and the outer sleeve  108  comprise one or more ports, one of the ports  107  of the outer sleeve  108  being visible in  FIG. 2 . During stimulation or fracking operations the one or more ports of the inner sleeve  109  are misaligned with the ports  107  of the outer sleeve  108 , to thereby prevent water from exiting port  107 . Instead water travels down the inner bore of treatment string  114  and exits through ported assemblies  20 . When the treatment fluid is switched, for example from water to sand, or when treatment of a previously stimulated interval  116  is complete and the treatment string  114  is to be moved to the next interval to be isolated and treated, the inner sleeve  109  is shifted or rotated mechanically to align the one or more ports of the inner sleeve  109  with the one or more ports  107  of the outer sleeve  108 . The mechanical actuation may take the form of the production string itself being moved, although other means of actuating the inner sleeve  109  would be obvious to a person of skill in the art and are included in the scope of the present invention. 
         [0036]    At this point, standing water or other treatment fluids in the inner bore of the treatment string  114  are displaced and caused to exit port  107  and travel up the annulus  18  to the surface where it can be collected and reused. 
         [0037]    As mentioned earlier, fluid flowing out of exit port  107  and travelling through annulus  18  to surface equalizes pressure on either side of the upper packer  106   a . this advantageously ensures that formation fluid from the treated interval  116  does not travel into the wellbore or up to surface. 
         [0038]    More preferably, a metering device may optionally be applied to the treatment string  114  or to the casing  16  to measure the flow of fluids being recycled back to surface. The metering device provides flow data on the flow rate of fluids being recycled back to surface to help operators determine when all of the recycled fluid has been recovered and when to close the diverter valve  110  and resume normal operation. When the system is ready for treating an interval through the ported assembly  20 , the inner sleeve  109  of the flow diverter valve  110  is shifted or rotated to misalign the one or more ports on the inner sleeve  109  with the one or more ports  107  on the outer sleeve  108 , thereby preventing fluid flow through these ports. Hydraulic pressure in the treatment string  114  helps to maintain the diverter valve  110  in a closed position. 
         [0039]    The above description is intended in an illustrative rather than a restrictive sense, and variations to the specific configurations described may be apparent to skilled persons in adapting the present invention to other specific applications. Such variations are intended to form part of the present invention insofar as they are within the spirit and scope of the claims below.