Abstract:
A single element hydraulic open hole packer is provided. A method is provided for multistage isolation and fluid treatment of a borehole, in which a first frac valve tool and a second frac valve tool are provided, a first packer is mounted downstream from the first frac valve tool, a second packer is mounted between the first frac valve tool and the second frac valve tool, a third packer is mounted upstream from the second frac valve tool, at least one of the first, second and third packers being a hydraulic set packer having a single packing element, the first frac valve tool being moveable between a closed and an open position, the second frac valve tool moveable between a closed and an open position; running the liner into a wellbore; hydraulically setting the single element packers; conveying means for moving the first frac valve tool to the open position; and forcing stimulation fluid out through the first frac sleeve tool.

Description:
FIELD OF INVENTION 
       [0001]    The present invention relates to devices for multi-stage, horizontal well isolation. 
       BACKGROUND OF THE INVENTION 
       [0002]    An important challenge in oil and gas well production is accessing hydrocarbons that are locked in formation and not readily flowing. In such cases, treatment or stimulation of the formation is necessary to fracture the formation and provide passage of hydrocarbons to the wellbore, from where they can be brought to the surface and produced. Fracturing of formations via horizontal wellbores traditionally involves pumping a stimulant fluid through either a cased or open hole section of the wellbore and into the formation to fracture the formation and produce hydrocarbons therefrom. 
         [0003]    In many cases, multiple sections of the formation are desirably fractured either simultaneously or in stages. Tubular strings for the fracing of multiple stages of a formation typically include one or more fracing tools separated by one or more packers. 
         [0004]    In some circumstances frac systems are deployed in cased wellbores, in which case perforations are provided in the casing to allow stimulation fluids to travel through the fracing tool and the perforated casing to stimulate the formation beyond. In other cases, facing is conducted in uncased, open holes. In the case of multistage, open hole fracing it is often a challenge to effectively isolate sections of the formation. This is due to the uneven inner surface of the open wellbore and the difficulty of making sufficient sealing contact between the packing elements of the packers and the surface. 
         [0005]    A number of packers are known in the art including swellable that comprise substances which react with hydrocarbons or water in the wellbore and are caused to swell. Swellable packers are dependent on sufficient exposure of the swellable substance to wellbore fluids that trigger swelling. The process of full packing off of the section to be fraced can take days to weeks using such swellable packers. Inflatable packers are also known in the art and are activated by inflation of packing elements with a gas or air. 
         [0006]    Hydraulic packers are typically defined as packers in which the packing elements can be activated by hydraulic pressure from wellbore fluids. Hydraulic packers have also been used in some open hole cases, however they typically require multiple packing elements per packer to provide sufficient contact with the open hole inner wellbore surface and to provide proper isolation for multistage packing. 
         [0007]    A need therefore exists in the art for packers that are simple in construction, small in size and effective at packing off in open hole wellbores. 
       SUMMARY OF THE INVENTION 
       [0008]    In one aspect, a single element hydraulic open hole packer is provided. In a second aspect, a single element hydraulic open hole packer is provided comprising a ratchet ring assembled on a mandrel of the open hole packer. 
         [0009]    A method is further provided for multistage isolation and fluid treatment of a borehole, the method comprising providing an apparatus for wellbore treatment including a liner, a first frac valve tool, a second frac valve tool upstream from the first frac valve tool along the liner, a first packer operable to seal about the liner and mounted on the liner downstream from the first frac valve tool, a second packer operable to seal about the liner and mounted on the liner between the first frac valve tool and the second frac valve tool, a third packer operable to seal about the liner and mounted on the liner upstream from the second frac valve tool, at least one of the first, second and third packers being a hydraulic set packer and at least one of the first, second and third packers having a single packing element, the first frac valve tool being moveable between a closed position and an open position permitting fluid flow through the first frac valve tool, the second frac valve tool moveable between a closed position and an open position permitting fluid flow through the second frac valve tool; running the liner into a wellbore in a desired position for treating the wellbore; hydraulically setting the single element packers; conveying means for moving the first frac valve tool to the open position; and forcing stimulation fluid out through the first frac sleeve tool. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0010]      FIG. 1  is a schematic diagram of a horizontal well fitted with the tools of the present invention; 
           [0011]      FIG. 2  is a cross sectional view of one example of the open hole packer  300  of the present invention, in various stages of use; and 
           [0012]      FIG. 3  is a schematic diagram of dual horizontals drilled in one well. 
       
    
    
     DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
       [0013]    A packing tool is provided that improves on isolating tools by providing increased safety during installation, reduced rig time and greater dependability. 
         [0014]    By combining both a slim outside diameter and short length, the present packing tool eliminates the need for handling pup joints, thereby reducing the rigidity of the liner. These features permit the more flexible, reduced outside diameter tool string to be deployed into the wellbore with greater ease. 
         [0015]    The present packer is more preferably an open hole packer that can be deployed with corresponding fracing tools along a liner and deployed into the open hole section of the wellbore. The present packers provide a means of isolating various stages of the horizontal wellbore. Once isolated, stimulation fluid can be pumped from surface and used for stimulating sections of the formation via any variety of fracing tools. 
         [0016]    With reference to  FIG. 1 , in a preferred method of deployment, the present packers can be deployed on a tubing string further comprising a float shoe or guide  50  at the toe of the liner, an activation tool  100  at a pre-determined distance from the guide shoe  50 , a first stage frac valve tool  200 , and then a series comprising the present open hole packer  300  alternated with subsequent stage frac valve tools  400  to a final cased hole packer  500 . It would be well understood by a person of skill in the art that  FIG. 1  merely represents one example of a tubular fracing string of tools and that additions, omissions and alterations to the illustrated string and its components can be made without departing from the scope of the present invention. 
         [0017]    The open hole packer  300  is illustrated on  FIG. 2  in both an unset (a) and set (b) position. The present open hole packer  300  has a single packing element  328 , differentiating it from other open hole packers that typically have dual elements and require multiple pistons to generate enough force to pack off the elements. A single pacing element  328  and single setting piston  302  allow the present open hole packer  300  to maintain its short length without requiring pup joints on either ends for handling. 
         [0018]    The present open hole packer  300  being shorter, and slimmer in outside diameter (O.D.) than typical packers provides greater ease of deployment and string flexibility. Safety issues on the rig floor during installation are reduced by elimination of pup joints. 
         [0019]    The present open hole packers  300  can be lifted by hand and hand threaded onto the liner, which is typically gripped at the rig floor, and then a section of upper liner, typically gripped in an elevator or similar device, can be lowered onto the open hole packer  300  and the one piece body of the packer  300  allows torque to be applied from the upper liner section, through the open hole packer  300  and into the liner to make up the liner string. 
         [0020]    The present open hole packer  300 , comprises a mandrel body  308  surrounded at least partially by a setting piston  302  and a single packing element  328 . The setting piston  302  comprises a first and a second diameter, D1 and D2 respectively. While D1 is exposed to wellbore fluids and experiences wellbore pressures, D2 is exposed to fluid pressure from within the liner. The product of the difference in these pressures and the difference in these diameters defines the force needed to displace setting piston  302  and move the open hole packer  300  from an unset (a) to a set position (b). A pair of seals  312  between the setting piston  302  and the mandrel body  308  guide this movement from unset to set. 
         [0021]    A ratchet ring  304  is located between the mandrel body  308  and the setting piston  302  that serves to prevent the piston  302  from backing off from a set position, thus ensure that the packing element  328  remains in a set position once set. Instead of having separate stroke lengths for both the ratchet ring  304  and the sealing members  312  on the setting piston  302 , the open hole packer&#39;s  300  novel design combines both features into one stroke. 
         [0022]    In the present open hole packer  300  the ratchet ring  304  is preferably formed as a split ring with an inner surface ratchet profile and an outer surface ratchet profile. Preferably the inner surface ratchet profile is finer than the outer surface ratchet profile. 
         [0023]    The ratchet ring  304  is first assembled onto the mandrel  308 , at least a part of the outer surface of the mandrel  308  having a ratchet profile that mate with the inner surface ratchet profile of the ratchet ring  304 . Preferably the ratchet ring  304  is assembled over one or more spring pins  306  installed on the mandrel  308  to control the position and alignment of the ratchet mechanism  304 . A locking body thread  310  formed on an inner surface of part of the setting piston  302  is then installed over the ratchet ring  304 . Preferably, the locking body thread  310  mates with the outer surface ratchet profile of the ratchet ring  304 . 
         [0024]    Typical packers have a ratchet ring installed into a locking thread of a piston. The locking body thread typically has spring pins installed it to control the position and alignment of the ratchet ring relative to the piston  302 . The piston with the ratchet ring must then be installed onto the mandrel body. This differs from the present invention in which the ratchet ring  304  is installed directly onto the mandrel  308  as the first stage of assembly. 
         [0025]    An O-ring land  320  on the mandrel  308 , has a greater diameter than the diameter of the ratchet profile on the mandrel  308 . In order to assemble the tool the ratchet ring  304  is first placed onto the mandrel  308  prior to the setting piston  302  being installed. In the present configuration both the setting stroke of the setting piston  302  and ratchet ring  304  are combined into one stroke, thereby allowing for a shorter length of open hole packer  300 . 
         [0026]    If the ratchet ring  304  and setting piston  302  had to be installed into the setting piston  302  first, then the diameter of the O-ring land  320  would need to be decreased, in turn causing a reduction in the setting area of the setting piston  302 . If the  0 -ring land  320  was reduced then an independent stroke for the ratchet ring  304  and an independent stroke for the setting piston  302  would be required, which in turn would necessitate added length to the open hole packer  300 . 
         [0027]    Orientation of the inner surface ratchet profiles of the ratchet ring  304  allow the piston  302  and ratchet ring  304  to travel from unset to set position along the mandrel body, while preventing the piston  302  and ratchet ring  304  from sliding back to an unset direction from a set position. Orientation of the outer surface ratchet profile of the ratchet ring  304  allows the piston  302  to slide over the outer surface of the ratchet ring and be it is being installed over the ratchet ring  304  and onto the mandrel  308 . Once the locking body thread  310  and the outer surface ratchet profile of the ratchet ring  304  mate, these mating profiles lock the ratchet ring  304  to the piston  302  when the piston  302  moves from an unset to a set position. 
         [0028]    The ratchet ring  304  and setting piston  302  have a larger ID than the mandrel  308 , thereby being able to straddle an upset  320  on the mandrel  308  without having to split the locking body  310  from the setting piston  302 . 
         [0029]    The open hole packer  300  is full bore, with no internal mandrel restrictions. It has the same I.D. as the liner. The modular design of the open hole packer  300  permits several packers  300  to be stacked together with various distances between them. If the bore hole, for example dipped out of the formation of interest and entered an adjacent formation then was drilled back into the formation of interest, that section of the borehole that was outside the formation of interest could be isolated by placing an open hole packer  300  at both ends of the dip effectively straddling that portion of the borehole that was not in the formation of interest. 
         [0030]    Preferably the present open hole packer  300  includes a stroke limiter  330  that acts to prevent the O-ring seals  312  on the setting piston  302  from disengaging the seal surface and opening up a leak path in the event that the open hole packer  300  is set in an oversize section of the bore hole. 
         [0031]    Actuation of the packing element  328  is caused by movement of the setting piston  302  from an unset to a set position. The setting piston  302  and the mandrel  308  define an expandable chamber  332  into which pressurized fluid flows and pushes against piston diameter surface D2, thereby expanding chamber  332  and moving setting piston  302  into the set position. The setting piston  302  in turn presses against the packing element  328  causing packing element to protrude into the wellbore until it comes in to sealing contact with the open hole wall, thereby separating and isolating sections of the wellbore on either side of the packing element  328 . The setting piston  302  is held in place and prevented from unsetting by ratchet ring  304 . 
         [0032]    The packing element  328  is comprised of a solid band of flexible material having a thickness such that an outer surface of the packing element  328  in its unset position sits flush with an outer surface of the setting piston  302 . Suitable materials for the packing element include any number of fluorocarbons and per-flourocarbons such as AFLAS™, HNBR, and Viton™, although it would be understood by a person of skill in the art that any flexible material showing resiliency and sufficient strength to maintain packing against wellbore fluid pressure would be suitable for the purposes of the present invention. 
         [0033]    In a preferred embodiment, the packing element  328  is thinner at its axial midpoint than everywhere else. More preferably, the packing element  328  is formed with a circumferential groove  336  of predetermined width and depth around its inner surface at the axial midpoint, such groove  336  creating a thinner middle portion of the packing element  328 . The groove  336  ensures that the packing element  328  protrudes from its axial midpoint, thereby providing even contact with the wellbore and a positive seal. In a further preferred embodiment, a packing element ring  334  is provided on the mandrel  308  onto which the packing element groove  336  sits. The packing element ring  334  fills in the void of the groove  336  and ensures that the midpoint of the packing element  328  protrudes outwards upon actuation, and does not fold inwardly into itself. 
         [0034]    One or more anti-extrusion expandable rings  314  hold the packing element  328  in place and press against the packing element  328  in actuation. More preferably, the anti-extrusion rings  314  are positioned between a backup ring  340  and the setting piston  302  at one end and between a further backup ring  340  and a lower cone  318  at a second end. 
         [0035]    The anti-extrusion rings  314  are preferably tightly trapped to prevent them from toggling on the mandrel  308  during installation. This is eliminates the chance of a loose anti-extrusion ring  314  from catching on objects while being run in the hole and potentially causing the liner to get stuck. 
         [0036]    The backup rings  340  is preferably shaped to allow an end of the setting piston  302  to travel along and wedge into one contour of the backup ring  340  while allowing the anti-extrusion ring  314  to travel along and wedge between the setting piston  302  and another contour of the backup ring  340 . A similar travel and wedging effect occurs in relation to the lower cone  318  and anti-extrusion ring  314  on a second end of the packing element  328 . Such wedging prevents the packing element  328  from extruding internally and prevents packing element creep during high differential pressures and helps centralize the open hole packer  300  while setting. 
         [0037]    The anti-extrusion rings  314  and packing elements  328  are preferably held in glands  316 . Tolerance accumulations on the anti-extrusion rings  314  and packing elements  328  create differences in the gland length  316 , and these differences in length are preferably compensated for by an adjustment mechanism, generally indicated by  322 , located adjacent the lower cone  318 . The adjustment mechanism  322  more preferably comprises a split ring  324  having a series of circumferential grooves that mate with corresponding grooves on the mandrel body  308 . The exact position of the split ring  324  is determined by the actual gland length  316  required by the anti-extrusion expandable rings  314  and packing element  328 . A cap  326  is then threaded onto the lower cone  318 , split ring  324  and mandrel body  308  to lock the adjustment mechanism  322  in place and set the gland length. The adjustment mechanism  322  ensures a tight fit of the anti-extrusion rings  314  to prevent them from toggling. Alternatively, a threaded cone may be employed in conjunction with a cap with a lock ring. In this embodiment the cap is anchored to the mandrel  308  and the adjustment can be made between the cone and the cap. 
         [0038]    The interaction of the present anti-extrusion rings  314  and backup rings  340  creates a barrier around the packing elements  328  after the open hole packer  300  is set. Without this barrier the packing elements  328  would not be able to maintain a seal at high differential pressures in a large I.D. borehole. This interaction also advantageously eliminates the need for multiple packing elements on the open hole packer to handle such high differential pressures. The single element packer configuration in turn reduces the necessary length of the open hole packer  300 , allowing it to be more easily installed and deployed. 
         [0039]    The ability to successfully deploy the open hole packer  300  containing ant-extrusion rings  314  permits the tool to have a slim O.D., and still effectively seal off the annular space between the liner and the wellbore. The use of the ant-extrusion rings  314  is in turn possible due to the compensating mechanism  322  that accommodates fluctuations in gland length  316 . 
         [0040]    In one example of operation of the present open hole packers  300 , a liner may be assembled with a float shoe  50 , an activation tool  100 , a liner, a first stage frac valve tool  200 , and then a series comprising a liner, the present open hole packer  300 , a liner and subsequent stage frac valve tools  400 . Optionally, an open hole anchor  600  may be used between the activation tool  100  and the first stage frac valve tool  200  to anchor the liner to the wellbore. 
         [0041]    Alternative to an open hole anchor  600  centralizers, stabilizers or other suitable means known in the art may also be used for this purpose. 
         [0042]    Preferably up to  40  frac valves  400 , on a 4½″ liner for example, separated with open hole packer  300   s  can be used in a string. A cased hole packer  500  is attached to the upper end of the liner. A latch seal assembly or other known means can be used to attach the cased hole packer  500  to the work string. 
         [0043]    The liner is run into the conditioned bore hole by a work string or on a frac string. At a predetermined depth the activation tool  100  is activated to stop fluid flow. Pressure in the liner now increases from a triggering pressure at which both the cased hole packer  500  and the open hole packers  300  begin to set, to a final pack off pressure at which the cased hole packer  500  and open hole packers  300  are fully set. A pressure test may optionally be performed inside the casing to determine if the cased hole packer  500  has set properly. If the liner was run on a work string, the latch seal assembly or other connection means can next be removed from the cased hole packer  500  and the work string and latch seal assembly are removed from the well and a frac string and latch seal assembly are deployed. Otherwise, if the liner was run downhole on a frac string, no replacement has to be made. 
         [0044]    Further pressure is applied to the fracture string. At a pre-determined setting pressure that is higher than the pack off pressure, the first stage frac valve tool  200  shifts to the open position and stimulation fluid is pumped into the formation and causes it to fracture. Proppant is then pumped into the fracture. Next subsequent frac valve tools, starting with that closest to the toe of the wellbore, are activated to thereby open communication between the inside of the liner and the isolated section of the formation between the two open hole packer  300  straddling the particular frac valve  400 . 
         [0045]    The stimulation fluid pumped through the frac valve  400  fractures the exposed formation between the open hole packers  300  used to isolate that stage. Whenever this stage has been fractured, a next frac valve  400  is activated and the process is repeated. The process can be repeated up to 40 times in total in a 4¼″ liner, for example. Other sizes of liners have a different number of frac valve tools  400  and open hole packers  300 . When all the desired stages have been fractured the well is allowed to flow and formation pressure from formation fluid flow acts to deactivate the frac valves and allow formation fluid flow into the liner. Afterwards the frac string and connecting means can be removed from the well. 
         [0046]    In the case of ball drop activated frac valve tools  400 , if desired, the seats of the frac valves  400  can be drilled out at a later date. 
         [0047]    In the event the operator needs to set the liner in an open hole, an open hole anchor  600  can replace the cased hole packer  500 . This scenario can exist whenever dual horizontals are drilled in one well, as seen in  FIG. 15 . The hydraulic set open hole anchor  600  is full bore. It is run in conjunction with an open hole packer  300  and tie back receptacle (not shown) to act as a means to seal and anchor the liner in the open hole. The tieback receptacle provides a means to deploy the liner then act as a means to seal and anchor the fracture string to the liner. 
         [0048]    The open hole anchor  600  is preferably full bore with no mandrel restrictions and has the same I.D. as the liner. Preferably it is operated with slips to anchor the liner to the formation. 
         [0049]    Preferably, after the bore hole has been drilled and before the liner is installed, a reamer trip is performed. The present reamer has a unique design to mimic the geometry of the stiffest components on the liner string. The present reamer has one set of blades instead of multiple sets and its reduced O.D. and short length enable it to be deployed and retrieved quickly while still ensuring the bore hole has no obstructions to impede running the liner with the present suite of fracturing tools. 
         [0050]    In the foregoing specification, the invention has been described with specific embodiments thereof; however, it will be evident that various modifications and changes may be made thereto without departing from the broader spirit and scope of the invention.