Patent Publication Number: US-8973661-B2

Title: Method of fracturing while drilling

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to and the benefit of U.S. Provisional Application Ser. No. 61/580,059, filed Dec. 23, 2011, the full disclosure of which is hereby incorporated by reference herein for all purposes. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to a method for use in producing fluid from a wellbore. More specifically, the invention relates to a method for fracturing discrete portions of a subterranean formation while at the same time drilling a wellbore in the formation. 
     2. Description of the Related Art 
     Hydrocarbon producing wellbores extend subsurface and intersect subterranean formations where hydrocarbons are trapped. The wellbores generally are created by drill bits that are on the end of a drill string, where typically a drive system above the opening to the wellbore rotates the drill string and bit. Cutting elements are usually provided on the drill bit that scrape the bottom of the wellbore as the bit is rotated and excavate material thereby deepening the wellbore. Drilling fluid is typically pumped down the drill string and directed from the drill bit into the wellbore. The drilling fluid flows back up the wellbore in an annulus between the drill string and walls of the wellbore. Cuttings produced while excavating are carried up the wellbore with the circulating drilling fluid. 
     Sometimes fractures are created in the wall of the wellbore that extend into the formation adjacent the wellbore. Fracturing is typically performed by injecting high pressure fluid into the wellbore and sealing off a portion of the wellbore. Fracturing generally initiates when the pressure in the wellbore exceeds the rock strength in the formation. The fractures are usually supported by injecting a proppant, such as sand or resin coated particles. The proppant is generally also employed for blocking the production of sand or other particulate matter from the formation into the wellbore. 
     SUMMARY OF THE INVENTION 
     Described herein is a method of operations in a subterranean formation. In one example the method includes providing a string of drill pipe with an attached drill bit to define a drill string and forming a wellbore through the formation using the drill string. A seal is formed from a portion of the drill string to a wall of the wellbore to create a sealed space from a bottom end of the wellbore to the seal. By pressurizing the sealed space, a portion of the formation is fractured that is adjacent the sealed space. The method can further include drilling the wellbore to a deeper depth so the bottom end of the wellbore is at a deeper depth and repeating steps of sealing and fracturing. Optionally, the bottom end of the drill bit is drawn upward from the bottom end of the wellbore between the steps of drilling and sealing. In one example, the seal is on the drill bit. The seal can be a packer, in this example forming the seal involves flowing fluid inside the packer to expand the packer into sealing engagement with the wall of the wellbore. In an alternative, the packer is provided on a collar on the drill bit. The bit can include a body with cutting blades on the body that define channels between the cutting blades, and sliding blades that selectively slide into the channels and into sealing engagement with lateral sides of the cutting blades. In this example, forming the seal involves sliding the sliding blades into the channels. The method can further include flowing drilling fluid inside the drill string, and discharging the drilling fluid from the drill bit during the step of forming the wellbore. Alternatively, pressurizing the wellbore is done by directing drilling fluid into the sealed space. 
     Also disclosed herein is a method of fracturing a subterranean formation. In an example of fracturing, a wellbore is bored in the formation by using a drill string having a drill bit attached to drill pipe. A seal is formed across an annular space between the drill string and a wall of the wellbore that creates a sealed space having an upper end at the seal and a lower end at a bottom end of the wellbore, and fluid is directed into the sealed space at a pressure that imparts a force onto the formation which exceeds a tensile stress in the formation and fractures the formation. The seal can be a packer that is activated by flowing pressurized fluid from an annulus of the drill string to the packer. Alternatively, the seal is formed on the bit by moving sliding blades on the bit into channels defined by cutting blades on the bit, wherein lateral sides of the sliding blades sealingly engage lateral sides of the cutting blades. Optionally, a secondary seal can be deployed above the bit. The bit can be moved upward from a bottom of the wellbore between drilling and sealing the wellbore. In one example, the fluid is a drilling fluid. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above-recited features, aspects and advantages of the invention, as well as others that will become apparent, are attained and can be understood in detail, a more particular description of the invention briefly summarized above may be had by reference to the embodiments thereof that are illustrated in the drawings that form a part of this specification. It is to be noted, however, that the appended drawings illustrate only preferred embodiments of the invention and are, therefore, not to be considered limiting of the invention&#39;s scope, for the invention may admit to other equally effective embodiments. 
         FIG. 1  is a side partial sectional view of an example embodiment of a drilling and fracturing system forming a wellbore in accordance with the present invention. 
         FIG. 2A  is a side view of an example of a drill bit for use with the system of  FIG. 1  in accordance with the present invention. 
         FIG. 2B  is a side view of an example of the bit of  FIG. 2A  in a sealing configuration in accordance with the present invention. 
         FIG. 3  is a side partial sectional view of an example of the system of  FIG. 1  initiating a fracturing sequence in accordance with the present invention. 
         FIG. 4  is a side partial sectional view of an example of the system of  FIG. 3  completing a fracturing sequence in accordance with the present invention. 
         FIG. 5  is a side partial sectional view of an example of the system of  FIG. 1  in a wellbore having fractures in multiple zones in accordance with the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE EXEMPLARY EMBODIMENTS 
     One example embodiment of a method of fracturing while drilling a wellbore through a formation is shown in a side partial sectional view in  FIG. 1 . In the example method of  FIG. 1  shown is a drilling system  20  excavating a wellbore  22  through a formation  24 . The drilling system  20  illustrated includes an elongated drill string  26  that receives a rotational force from a drive system  28  shown schematically represented on the surface and above an opening of the wellbore  22 . Example embodiments of the drive system  28  include a top drive as well as a rotary table. A number of segments of drill pipe  30  threadingly attached together form an upper portion of the drill string  26 . An optional swivel master  32  is schematically illustrated on a lower end of the drill pipe  30 . As is known, implementation of the swivel master  32  allows the portion of the drill string  26  above the swivel master  32  to be rotated without any rotation or torque being applied to the string  26  below the swivel master  32 . A directional drilling assembly  34  is shown optionally provided on a lower end of the swivel master  32 . The directional drilling assembly  34  may include gyros or other directional type devices for steering the lower end of the drill string  26 . Also optionally provided is an intensifier  36  coupled on a lower end of the directional drilling assembly  34 . 
     In one example, the pressure intensifier  36  receives fluid at an inlet adjacent the drilling assembly  34 , increases the pressure of the fluid, and discharges the fluid from an end adjacent a drill bit assembly  38  shown mounted on a lower end of the intensifier  36 . The bit assembly  38  includes a drill bit  40 , shown as a drag or fixed bit, but may also include extended gauge rotary cone type bits. Cutting blades  42  extend axially along an outer surface of the drill bit  40  and are shown having cutters  44 . The cutters  44  may be cylindrically shaped members, and may also optionally be formed from a polycrystalline diamond material. Further provided on the drill bit  40  of  FIG. 1  are nozzles  46  that are dispersed between the cutters  44  for discharging drilling fluid from the drill bit  40  during drilling operations. As is known, the fluid exiting the nozzles  46  provides both cooling of cutters  44  due to the heat generated with rock cutting action and hydraulically flushes cuttings away as soon as they are created. The drilling fluid also recirculates up the wellbore  22  and carries with it rock formation cuttings that are formed while excavating the wellbore  22 . The drilling fluid may be provided from a storage tank  48  shown on the surface that leads the fluid into the drill string  26  via a line  50 . 
       FIG. 2A  is a side view example of the drill bit  40  that further includes a fracturing nozzle  52  shown formed through a body  54  of the drill bit  40 . The nozzles  46  ( FIG. 1 ) and fracturing nozzle  52  are both selectively in fluid communication with fluid provided from the tank  48  and may each be opened or closed at designated times. Fluid in the tank  48  can flow through line  50  and the drill string  26 , and then exit the nozzles  46  from the drill bit body  54 . In one example embodiment, when the nozzles  46  are in an open condition, the fracturing nozzle  52  is in a closed position so that no fluid flows from the fracturing nozzle  52  through the bit body  54 . Conversely, an example of operation exists wherein the fracturing nozzle  52  is in an open position so that fluid exits the fracturing nozzle  52  at a same time that the nozzles  46  are in a closed position and without fluid exiting through the nozzles  46 . 
     Further illustrated in  FIG. 2A  are elongated spaces between adjacent blades  42  on the bit body  54  that extend substantially parallel with an axis A x  of the bit and define channels  56  along the outer surface of the body  54  between the blades  42 . On the body  54  and above upper ends of the blades  42  are sliding blades  58 , that as will be described in more detail below, are axially movable from their location as shown in  FIG. 2  and into the channels  56 . In one example, when the sliding blades  58  are moved into the channels  56 , respective lateral sides of the sliding blades  58  and cutting blades  42  sealingly engage one another. 
     Referring now to  FIG. 3 , illustrated is an example of the drilling system  20  ( FIG. 1 ) initiating a sequence for fracturing the formation  24 . In the example of  FIG. 3 , the bit  40  is shown at a depth in the wellbore  22  adjacent a designated zone Z where a fracturing operation is to occur. Identifying the location of zone Z for fracturing can include using real time data, such as surface mud logging, logging while drilling, or downhole data such as rate of penetration (ROP). A sensor or sensors (not shown) at or near the bit  40  may be used to collect the data, and data can be sent uphole via telemetry, including mud pulse telemetry. In this example of fracturing, the nozzles  46  are closed thereby restricting fluid from exiting the bit  40  through the nozzles  46 . In contrast and as discussed above, the fracturing nozzles  52  are shown set into an open position so that fluid may be discharged from the bit  40  through the fracturing nozzles  52 . Also shown in  FIG. 3  is that the drill string  26  has been positioned so that the lower end of the bit  40  is set a distance above a bottom end  59  of the wellbore  22 , where the distance may range from less than about a foot up to around 10 feet, and all distances therebetween. 
     A collar  60  is further illustrated on the drill string  26  and proximate an upper end of the bit  40 . On an outer circumference of the collar  60  is a packer  62  that is shown being inflated and expanding radially outward from the collar  60  and into sealing engagement within inner surface of the wellbore  22 . The packer  62  when inflated and sealing against the wellbore  22  defines a space  64  between the bit  40  and wellbore  22  that is sealed from portions of the wellbore  22  that are above the collar  60 . In the example of  FIG. 3 , the space  64  extends from the packer to the wellbore bottom  59 . In an example, after defining the sealed space  64 , fluid is discharged from the fracturing nozzles  52  into the space  64 . The fluid pressure in the space  64  exerts a stress on the formation  24  that exceeds a tensile stress in the rock formation  24 . 
     Referring now to  FIG. 2B , an example of the bit  40  is shown wherein blades  42  extend radially outward from the bit body  54  and into contact with the inner surface of the wellbore  22 . Further shown are that the sliding blades  58  have been moved downward into the channels  56  between the blades  42 , thereby occupying a portion of the channels  56 . Also, as described above, the opposing lateral sides of the blades  42 ,  58  engage one another into sealing contact. The sliding blades  58  also extend radially outward into contact with the wall of the wellbore  22  and thus create a seal in the annular space between the bit  40  and wall of the wellbore  22 . Slots  66  are shown in the body  54  that each may receive a connecting arm (not shown) attached to an inner surface of the sliding blades  58 . The slots  66  can guide the connecting arms, and thus the sliding blades  58 , along a designated path. Further, the slots  66  can provide an opening through the body  54 , so the connecting arms can couple to an actuator for moving the sliding blades  58 . In the example of  FIG. 2B , the space  64 B extends below the collar  60  and packer  62  and into the spaces between the bit body  54  and inner surface of the wellbore  22  and is smaller than the space  64  ( FIG. 3 ) formed with the configuration of the bit  40  of  FIG. 2A . The channels  56  occupy some portion of the sealed space  64 B. An advantage of the sliding blades  58  is that because the sealed space  64 B is shorter than sealed space  64 , even more discrete locations in the wellbore  22  can be fractured. 
     Referring now to  FIG. 4 , an example of fracturing in the formation  24  is illustrated. A fracture  68 , which was initiated at the wellbore wall, is shown extending laterally into the formation  24 . The fracture  68  of  FIG. 4  can be created by pressurizing fluid  70  in the sealed space  64  to a pressure that exerts a force onto the formation  24  greater than a tensile strength of the formation  24  where the fracture  68  takes place. Examples exist where the sealed space  64  is formed by deploying the packer  62 , moving sliding blades  58  into the channels ( FIG. 2B ) to form space  64 B, or both. In one example, the packer  62  acts as a secondary seal to the seal formed by moving the sliding blades  58  between the cutting blades  42 . Example pressures in the space  64  may range from about 25,000 psi to about 30,000 psi. The fluid  70  may be partially pressurized at the tank  48  alone, and or may be further pressurized in the intensifier  36 . In the example of  FIG. 4 , the fluid  70  is illustrated in the fracture  68  after having been forced therein from the space  64  below the deployed packer  62 . Optionally, the fluid  70  can include drilling fluid, a dedicated fracturing fluid, solid-free acidic brine, combinations thereof, or other non-damaging type of fluid. 
     In one example, from about 100 barrels to about 150 barrels of fluid are discharged from the fracturing nozzle  52  during the step of fracturing the formation  24 . Yet further optionally, a proppant may be included within the fracturing fluid for maintaining the fracture  68  in an open position for enhancing permeability, as well as trapping sand that may otherwise flow into the wellbore  22  from the formation  24 . While the fracture  68  is shown to be in a generally horizontal position, other embodiments exist wherein the fractures are oriented to extend along a plane of minimum horizontal principal stress so that multiple transverse fractures can be created that extend further into the rock formation away from the wellbore wall. Further, the swivel master  32  may be initiated during fracturing so that the portion of the drill string  26  above the swivel master  32  may continue to rotate without rotating the portion below the swivel master  32 . Rotating the drill string  26  above the swivel master  32  can avoid inadvertent adherence of the drill string  26  to the wall of the wellbore  22 . In an alternate embodiment, the drilling may be underbalanced or can be managed pressure drilling for assessing an effect of fracturing the formation. Well control issues due to greater than anticipated fluid migration into the formation from fracturing may be addressed by removing or deactivating the intensifier  36 , reducing the volume of the fluid  70 , as well as monitoring fluid pressures and flows. Optionally, a sufficient volume of backup drilling fluid can be provided proximate to the drilling system  20  for replacing any lost fluids as well as integrating a rotating control device (not shown) with the drilling system  20 . 
     Optionally, as illustrated in  FIG. 5 , the drilling system  20 , which may also be referred to as a drilling and fracturing system, may continue drilling after forming a first fracture  68  and wherein the process of creating a fracture is repeated. As such, in the example of  FIG. 6  a series of fractures  68   1-n  are shown formed at axially spaced apart locations within the wellbore  22 . Further illustrated in the example of  FIG. 5  is that the packer  62  has been retracted and stowed adjacent the collar  60  thereby allowing the bit  40  to freely rotate and further deepen the wellbore  22 . 
     The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.