Abstract:
The present invention is directed to a bottom-up method of fracturing a multi-zone subterranean formation intersected by a wellbore that enables one zone to be fractured while at the same time flowing previously placed fracture fluid from one or more other zones back to the surface. The method employs a bottom-hole assembly (“BHA”) that is attached to the bottom end of a tubing string. The BHA includes a hydra jetting sub, a centralizer, a packer and valve sub. The hydra jetting sub is used to perforate and initiate the fracture in the zones of interest. The zones are fractured by pumping fracturing fluid down the annulus formed between the tubing string and the wellbore. The previously placed fracture fluid flows back to the surface through the tubing string. It enters through the valve sub in the BHA.

Description:
BACKGROUND  
       [0001]     The present invention relates generally to methods for fracturing subterranean formations having tight lenticular gas sands or multiple pay sands and more particularly to a fracturing method that allows one zone of the formation to be fractured while simultaneously flowing back previously placed stimulation and/or fracture fluids from one or more other zones in the formation.  
         [0002]     Many subterranean formations containing hydrocarbon reservoirs suffer from the problem of having insufficient permeability or productivity to enable the hydrocarbons to be recovered at the surface in an effective and economical manner. A number of techniques have been developed to increase the permeability or productivity of these formations. The most common techniques include hydraulically fracturing the subterranean formation and/or chemically stimulating the formation.  
         [0003]     Hydraulic fracturing commonly involves injecting fluids into the formation at sufficiently high pressures to cause the formation to fracture. The fractures are then injected with a granular material known as a proppant, which may include sand, ceramic beads or other similar material. The proppants hold the fracture open after the pressure is released. The proppant-filled fractures create a higher permeability flow-path for the hydrocarbons to follow from the reservoir to the wellbore than that occurring naturally in the subterranean formation. Chemical stimulation techniques involve pumping certain chemicals into the formation, such as acid-based fluids, that etch away a path in the formation through which the hydrocarbons can flow or otherwise alter the properties of the formation so as to enhance its permeability.  
         [0004]     After the flow paths have been created, regardless of the technique, the treatment fluids that have been injected into the formation must be recovered. The treatment fluids are recovered for a number of reasons. For one, some of these treatment fluids are expensive and can be reused in other fracturing and/or stimulating other wellbores. Furthermore, it is believed that certain treatment fluids, especially water-based treatment fluids, left in the formation for extended periods of time can actually inhibit the flow of hydrocarbons rather than enhance it. This damage can be compounded by time and depth of fluid penetration. The process reduces and in some instances prohibits the hydrocarbons from flowing toward the wellbore. This condition is known as imbibement. The step of producing the fracture or stimulation fluid to the surface is known as “flow back.” 
         [0005]     In conventional fracture methods, the fracture/stimulation fluids are not circulated back to the surface until after the fracture/stimulation procedure has been completed, which can sometimes take several days or even weeks if multiple zones are being fractured using conventional fracturing/stimulation techniques. After that period of time, the amount of imbibement can be significant.  
         [0006]     In addition to the ill effects of imbibement, which are caused using conventional fracture/stimulation methods to complete a well, the time lost associated with these techniques is significant and can result in potentially significant lost revenue. This is because each of the steps associated with fracturing/stimulating a multi-zone formation have conventionally been performed separately. Furthermore, conventional fracturing/stimulation techniques require multiple trips into and out of the well of downhole tools to accomplish the various fracturing/stimulation steps. For example, the steps of perforating the formation, fracturing the formation and flowing the treatment fluid out of the fracture back to the surface all typically require multiple trips of various downhole tools into and out of the well to complete. This can be very time consuming, especially when multiple pay zones are involved.  
         [0007]     A number of solutions have been proposed to reduce the number of trips needed to fracture multiple zones in a multi-zone formation. In a number of these solutions, the fractures are formed starting at the bottom of the well and working upward. In one such method, the first fracture is initiated by perforating the formation in the first zone using a gun perforator that has been lowered into the well using a wireline. After the perforations have been formed, a tubing with a packer is lowered and set beneath the perforations. Then the fracture fluid is pumped down the annulus between the tubing and the casing or wellbore as the case may be. After the fracture has been formed, the packer is unset and the tubing raised to a location above the next zone to be fractured. Then the gun perforator is again lowered into the well adjacent to the region to be fractured to perforate that region. The gun perforator is again removed from the well using the wireline. Next, the tubing is lowered and the packer set between the perforated second zone and the fractured first zone. The fracture fluid is then pumped down the annulus into the second zone so as to fracture that zone. This process is repeated if additional zones need to be fractured. After all of the zones have been fractured then the fracture/stimulation fluid is produced. This solution saves a number of process steps by leaving the tubing in the well during the perforating and fracturing steps and by using a removable packer. However, it still requires multiple trips into and out of the well and thus allows for a substantial amount of imbibement to occur.  
         [0008]     A number of solutions propose using a bottom-hole assembly (“BHA”), which combines the packer with a multi-stage perforating gun, which in turn is attached to a tubing string or jointed pipe. In one solution, the multi-stage perforating gun is detachably secured to the packer, which is disposed below the perforating gun. In another solution, the packer is attached above the multi-stage perforating gun. In the latter solution, a depth-control device may be incorporated into the BHA or at the surface to assist the well operator in accurately positioning the tool within the wellbore during perforation and fracturing.  
         [0009]     The advantage of these solutions is that since the perforating gun is attached to the packer, the perforating gun does not have to be recovered at the surface between perforation steps. Therefore, a plurality of production zones can be perforated and fractured by a single run into the well in a continuous unbroken sequence, without withdrawing the tubing string, perforating gun or packer from the well before all the zones have been perforated and treated. A drawback of this solution, however, is that it does not allow flow back of the hydraulic fracture/stimulation treatment fluid in the multiple zones until after all of the zones have been perforated and fractured. Accordingly, this solution is subject to a certain amount of undesirable imbibement.  
         [0010]     Therefore, it is desirable to be able to perforate and fracture multiple production zones in the formation while simultaneously flowing back previously placed hydraulic fractures/stimulation treatment fluids in zones that have already been perforated and fractured all in a single trip. The assignee of the present invention has carried out such a method using a top-down approach, i.e., by perforating and fracturing zones in a sequence starting at a location up hole and working toward the bottom of the well. The tool employed in this method was a BHA having an expandable packer connected to a tubing string, a centralizer connected to the packer, a hydra jetting sub connected to the centralizer and a ball sub connected to the hydra jetting sub, such as the one illustrated in  FIG. 1A .  
         [0011]     The assignee&#39;s prior method is carried out in the following sequence. First, Zone  1  is perforated using the hydra jetting sub, then it is fractured, and then the BHA is moved downhole toward Zone  2  washing down the wellbore in the process, as shown in  FIG. 1A . Next, a ball is circulated down the tubing until it reaches the ball sub, as shown in  FIGS. 1B and 1C . Once the ball has landed, the fluid exits the jets in the hydra jetting sub to thereby perforate Zone  2 , as shown in  FIG. 1C . Once Zone  2  has been perforated, the ball is circulated back up the tubing to the surface using the pressure from the formation, as shown in  FIG. 1D . Next, the BHA is moved up hole and the packer is set just below Zone  1 , as shown in  FIG. 1E . Then the fracturing fluid is pumped down the tubing into the perforations in Zone  2  causing Zone  2  to fracture, as shown in  FIG. 1E . The previously placed fracture fluid from Zone  1  is simultaneously recovered up the annulus. Next, the BHA is moved downhole toward Zone  3  washing down the wellbore in the process, as shown in  FIG. 1F . The BHA is then moved downhole so that the hydra jetting tool is adjacent to Zone  3 . The ball is again landed in the ball sub, and then fluid in pumped through the hydra jetting tool to perforate Zone  3 , as shown in  FIG. 1G . The process continues until all of the desired zones have been perforated, fractured and had their fracturing fluid flowed back to the surface.  
         [0012]     The assignee&#39;s prior method of simultaneously perforating, fracturing and flowing back multiple zones in a subterranean formation overcomes many of the disadvantages of prior fracturing methods and has proven to be a useful method for treating multiple zones in a subterranean formation in the Northeastern United States. There are some formations, however, where the top-down fracturing method is less than desirable, for example, those found in the United States and Canadian Rockies. Furthermore, top down fracturing has several drawbacks.  
         [0013]     The top down completion method requires the fracturing fluid to be pumped down the tubing which results in a larger ID tubing being needed to facilitate the flow rates needed to fracture the reservoir. A drawback of using larger pipe (2.375-2.875 inch diameter) is that it is relatively difficult to handle in the wellbore compared to smaller pipe sizes (1.5-2.0 inch diameter) and is more expensive. Also, in the top down method, the previously placed fracturing fluid is produced up the annulus, which impinges against the tubing string and therefore can cause damage to the tubing string. Furthermore, in the top down method the previously fractured zones are above the packer and flowing these zones back may result in proppant building up on the top of the packer. Additionally, top down completions diminish the annular pressure and mechanical integrity, which can greatly compromise future recompletion efforts.  
         [0014]     It is therefore desired to have a bottom-up method of simultaneously perforating, fracturing and flowing back multiple zones that overcomes some of the drawbacks of the assignee of the present invention&#39;s prior treatment method.  
       SUMMARY  
       [0015]     The present invention is directed to a method of fracturing a multi-zone subterranean formation intersected by a wellbore. The method includes the step of running a BHA attached to an end of a tubing string into the wellbore adjacent to a first zone to be fractured. The BHA comprises a hydra jetting sub having a plurality of jet ports, a centralizer attached to the hydra jetting sub, and a packer and valve sub attached below the hydra jetting sub. The first zone is perforated by injecting a hydraulic fluid into the subterranean formation through the jet ports of the hydra jetting sub. After the first zone is perforated, the BHA is moved downhole below the first zone. The packer is then set. Next, a fracture fluid is pumped down an annulus formed between the tubing string and the wellbore and into the perforations formed in the first zone. The packer is then unset and the BHA is pulled up hole adjacent to a second zone. The terms “up hole” and “downhole” refer to locations along the wellbore irrespective of depth. Thus, one location in the wellbore may be up hole of another even though the other location is closer to the surface than the other location in absolute depth terms if the up hole location is closer to the surface as measured along the path of the wellbore.  
         [0016]     The second zone is then perforated and the fracture initiated by injecting a hydraulic fluid into the subterranean formation through the jet ports of the hydra jetting sub. Then, the BHA is moved downhole between the first zone and the second zone and the packer is set to isolate the first zone from the second zone. A fracture fluid is then pumped down the annulus and into the perforations formed in the second zone. At the same time that the fracture fluid is being pumped down the annulus to fracture the second zone, the previously placed fracturing fluid in the first zone flows back to the surface through the BHA and tubing string. The flow back fluid enters the BHA through the valve sub, which is attached at the bottom end of the BHA.  
         [0017]     The method can be repeated for as many zones as are desired to be fractured. The method enables the next zone to be fractured while the previously placed fracture fluid in all the other zones downhole of that zone flows back to the surface via the BHA and tubing string. The packer isolates the zone being fractured from all of the other zones downhole of that zone. Therefore, the present invention provides a bottom-up method of fracturing a multi-zone subterranean formation allowing for simultaneous flow back.  
         [0018]     The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the exemplary embodiments, which follows.  
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0019]     A more complete understanding of the present disclosure and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, which:  
         [0020]      FIGS. 1A-1G  illustrate the steps in carrying out a prior top-down fracturing method.  
         [0021]      FIGS. 2 and 2 A illustrate an embodiment of a BHA used in accordance with the method according to the present invention.  
         [0022]      FIGS. 3A-3F  illustrate use of the BHA shown in  FIG. 2  in carrying out the steps of fracturing a multi-zone subterranean formation in accordance with the present invention.  
         [0023]      FIGS. 4A and 4B  are a flow chart illustrating the steps of fracturing a multi-zone subterranean formation in accordance with the present invention.  
     
    
     DETAILED DESCRIPTION  
       [0024]     The details of the present invention will now be described. Turning to  FIG. 2 , a BHA for use in the method of the present invention is illustrated generally by reference numeral  10 . The BHA  10  is attached to the bottom end of a tubing string  12 . The tubing string  12  can be a coiled tubing, jointed tubing or other downhole deployment device that can communicate fluid downhole. The BHA  10  also includes a centralizer sub  14 , which includes a plurality of centralizer members  16  which centralize the tool within the casing or open hole of the wellbore as the case may be.  
         [0025]     The BHA  10  further includes a hydra jetting sub  18  connected to the centralizer sub  14 . The hydra jetting sub  18  includes a plurality of jet ports  20 , which direct a hydraulic fluid into the subterranean formation at a very high pressure, specifically a pressure high enough to perforate the subterranean formation and/or initiate a fracture in the subterranean formation. The jet ports  20  include nozzles (not shown) formed of a carbide or ceramic material to resist the corrosive effects of ejecting the hydraulic fluid from the sub at such high pressures.  
         [0026]     The BHA  10  further includes a packer  22  connected to the hydra jetting sub  18 . The packer  22  is a compression-type packer and operates as follows. By rotating the tubing string  12 , a plurality of wedges  24  in the packer align with a corresponding plurality of tapered sealing members  26  (shown in  FIG. 2A ). By pushing down on the tubing string  12 , the downward force (indicated by the arrow F) causes the sealing members  26  via the wedges  24  into engagement with the inside surface of a casing within the wellbore. The packer  22  is unset by pulling up on the tubing string  12  to remove the force on the sealing members  26  applied by the wedges  24  and rotating the tubing string so as to place the wedges out of alignment with the sealing members. As those of ordinary skill in the art will appreciate, other types of re-settable sealing mechanisms besides a compression-type packer can be employed.  
         [0027]     The BHA  10  further includes a valve sub  28  connected to the hydra jetting sub  18 . The valve sub  28  may include a check valve, such as ball valve  30  (shown in  FIG. 2 ) or a flapper valve or the like. The valve sub  28  permits fluid to flow up the BHA  10  and tubing string  12  when the valve connected to the tubing string  12  at the surface is open and the formation pressure controls the fluid flow. The valve sub  28  blocks flow out of the bottom end of the BHA  10  when the hydraulic fluid ejected from the hydra jetting sub  18  is being pumped down the tubing string  12 .  
         [0028]     As those of ordinary skill in the art will recognize, the BHA  10  may include additional equipment not shown, e.g., wash tools, circulation port subs, pressure equalization subs, wireline connection subs, pressure gauges, temperature gauges, casing collar locators, shear subs, fishing necks, re-settable mechanical slips, and other auxiliary equipment for handling auxiliary operations and measurements that may be needed downhole during the fracturing method.  
         [0029]     A fracturing method in accordance with the present invention will now be described with reference to  FIGS. 3A-3F  and  4 . First, in step  100 , a wellbore  2  is drilled into multi-zone subterranean formation  1  using known drilling techniques. Next, in step  102 , the BHA  10  is run into the wellbore  2  with the hydra jetting ports  20  being disposed adjacent to the first zone to be fractured in the subterranean formation  3 . In step  104 , hydraulic fluid is pumped down the tubing string  12  and through the hydra jetting ports  20  into the first zone  3  at sufficient pressure to perforate the first zone. In step  106 , the fluid is ejected from ports  20  at sufficient enough pressure and for sufficient enough time to initiate a fracture in the first zone  3 . Next, in step  108 , the BHA  10  is moved downhole below the first zone  3 . In step  110 , the packer  22  is set. In step  112 , a fracture fluid is pumped down an annulus  11  formed between the tubing string  12  and the wellbore  2  and into the perforations  40  formed in the first zone  3  so as to fracture the first zone  3 .  
         [0030]     In step  114 , the packer  22  is unset. In step  116 , the BHA  10  is pulled uphole so that the jet ports  20  of the hydra jetting sub  18  are disposed adjacent to a second zone  5  of the subterranean formation. In step  118 , hydraulic fluid is pumped down the tubing string  12  and through the hydra jetting ports  20  into the second zone  5  at sufficient pressure to perforate the second zone, as shown in  FIG. 3A . In step  120 , the fluid is ejected from ports  20  at sufficient enough pressure and for sufficient enough time to initiate a fracture in the second zone  5 , as shown in  FIG. 3B . In step  122 , the packer  22  is set between the first zone  3  and the second zone  5 . Next, in step  124 , a fracture fluid is pumped down an annulus formed between the tubing string  12  and the wellbore  2  and into the perforations  50  formed in the second zone  5  so as to fracture the second zone  5 . Next, in step  126 , simultaneous with steps  120 - 124 , the previously placed fracturing fluid in the first zone  3  is flowed back to the surface through the BHA  10  and tubing string  12 , as indicated by the arrows flowing up the valve sub  28  in  FIG. 3C .  
         [0031]     In steps  128  and  130 , the packer  22  is unset and the BHA  10  is moved up hole (as shown in  FIG. 3D ) adjacent to a third zone  7 , respectively. In step  132 , hydraulic fluid is pumped down the tubing string  12  and through the hydra jetting ports  20  into the third zone  7  at sufficient pressure to perforate the third zone, as shown in  FIG. 3E . In step  134 , the fluid is ejected from ports  20  at sufficient enough pressure and for sufficient enough time to initiate a fracture in the third zone  7 . In step  136 , the packer  22  is set between the second zone  5  and third zone  7 . Next, in step  138 , a fracture fluid is pumped down the annulus  11  and into the perforations  60  formed in the third zone  7  so as to fracture the second zone  5 . Next, in step  140 , simultaneous with steps  134 - 138 , the previously placed fracturing fluid in the first and second zones  3  and  5  is flowed back to the surface through the BHA  10  and tubing string  12 , as indicated by the arrows flowing up the valve sub  28  in  FIG. 3F .  
         [0032]     Next, step  142 , which is to repeat steps  128 - 140 , may be repeated for each additional zone that the well operator desires to fracture. As those of ordinary skill in the art will appreciate, if only two zones are desired to be fractured, only steps  100  through  128  are to be performed. Once all of the desired zones have been fractured, the BHA  10  may be pulled up hole to a location above all of the fractured zones where the packer  22  may be set and the remaining previously placed fracture fluid may be recovered up the BHA  10  and tubing string  12 . Alternatively, the BHA  10  can be pulled completely out of the hole and the previously placed fracture fluid may be recovered up the wellbore  2 . As those of ordinary skill in the art will also appreciate, not all of the steps that would ordinarily be performed in carrying out the method according to the present invention are described. For example, the wellbore  2  may be lined with a casing, which may or may not be cemented to the wellbore  2 . Those of ordinary skill in the art would know under what circumstances to case (or not case) the wellbore  2  and whether such casing should be cemented to the wall of the wellbore  2 . Furthermore, the steps of washing the wellbore  2  down is not specifically recited. Washing or circulating the wellbore is needed if proppant or other sediments settle out of the fluid and collect at the bottom. Circulating the well may also be needed after perforating and before fracturing because it is undesirable for the fluid in the annulus to make its way into the reservoir.  
         [0033]     Therefore, the present invention is well-adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While the invention has been depicted, described, and is defined by reference to exemplary embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.