Patent Publication Number: US-2016230523-A9

Title: Mechanized slot drilling

Description:
RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Application No. 61/866,400 filed Aug. 15, 2013, which is incorporated herein by reference. 
    
    
     FIELD OF THE INVENTION 
     The inventions relates to systems and methods for providing plane opening in formations. 
     BACKGROUND TO THE INVENTION 
     Considerable amounts of natural gas have been found to be producible from formations such as source rocks, shale, and other low porosity and permeability formations by drilling long horizontal wells and stimulating the wells with multiple propped fractures so that a large volume of formation within a short distance of the well is connected to the wellbore. Hydrocarbons trapped in such formations then migrate toward the volume connected to the wellbore at rates that can result in economic production of the hydrocarbons from formations that were previously considered to be uneconomic to produce. Although fracturing of the formations can result in profitable production, it would be desirable to have an alternative to fracturing, to provide volumes connected to wellbores within these formations. 
     U.S. Pat. No. 7,647,967 to Coleman et al. suggests a method to remove mass from a formation between two connected wellbores by using a flexible cutting cable such as a segmented diamond cutting saw that is pulled reciprocally between two wellbores. The wellbores are drilled and connected so that the cutting cable may be inserted into one of the two, and then fished from connecting wellbore, and then repeatedly pulled back and forth, removing formation between the wellbores to form an opening in the shape of a plane. 
     U.S. Pat. Nos. 4,232,904 and 5,033,795 suggest methods to remove minerals such as coal from seams using a chain cutter that is pulled through the seam initially from a tunnel drilled either in a U-shape or from two sides from which access to the seam is provided by excavation or from the seam outcropping. 
     Patent application publications WO2010/074980, WO2012/052496 and US 2011/0247810 suggest variations of using a chain cutter pulled back and forth between wellbores for the purpose of hydrocarbon production. 
     Each of the references suggesting using flexible cutting cables rely on energy transferred from rigs on the surface by lifting or reciprocating the cutters to provide energy, by lateral side force, for cutting the slot in the formation. The net energy that can be transmitted to cutting formation is limited by the strengths of the cutting cables and the speed with which surface rigs are able to reciprocate the cutting cables. The result is that formation is removed at a relatively slow rate. 
     SPE paper 68441 by Philip Head et al. describes an electric coiled tubing drilling system that utilizes a fit for purpose electric motor to drive a steerable drill bit. Typically, steerable motors are driven by hydraulic positive displacement motors that utilize energy from pressure of the drilling fluid. With the electric drilling motor, drilling fluid properties and flow rates are not constrained by the requirements of both the formation and drilling 
     SUMMARY OF THE INVENTION 
     A system is provided for providing access to surfaces within a formation comprising: a cylindrical cutting assembly having a first end and a second end: a cutting element positioned radially around a circumference of the cylindrical cutting assembly; a means for rotating the cutting element around the cutting assembly; and a means for moving the cutting assembly through a wellbore wherein the cutting assembly is biased against one side of the wellbore. 
     A method is also provide for providing a slotted opening in a formation, the method comprising: providing a wellbore from a first surface location to a second surface location; inserting into the wellbore a cylindrical cutting assembly connected to at least two wellbore tubular, one of the wellbore tubulars extending to each of the first surface location and the second surface location; and rotating the radial cylindrical cutting element. 
     A system that may be used to accomplish this method is also provided, the apparatus comprising: a cylindrical cutting assembly having a first end and a second end: a cutting element positioned radially around a circumference of the cylindrical cutting assembly; a means for to rotating the cutting element around the cutting assembly; and a means for moving the cutting assembly through a wellbore wherein the cutting assembly is biased against one side of the wellbore. 
     The method and apparatus of the present invention may provide more energy to be converted to mechanical motion within the wellbore to enable more rapid creation of slot volume than a system that requires mechanical motion be provided from the surface facilities by reciprocating a cutting element. 
     This rotating cutting action may be provided from the electric motors within the wellbores, or could be enhanced or replaced by rotating the entire drilling assembly up to the max torque allowed by the pipe having strength similar to wellbore tubular used in conventional directional drilling. Pipe rotation is induced to the entire drill string from the rotary table of the rig and drilling trajectory is planned to maximize the rotation (therefore resulting cutting action) while minimizing bend curvature and concentration of torque and bending moment in the drill pipe assembly. 
    
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         FIG. 1  is a schematic figure of a wellbore connecting wellheads at two surface locations with a horizontal U-shaped section. 
         FIG. 2  is a schematic figure of a wellbore connecting wellheads at two surface locations with a horizontal U-shaped section where a portion of the formation between the parallel legs of the U-shaped section has been removed according to the present invention. 
         FIG. 3  is a schematic of the apparatus of the present invention connected at each end to a wellbore tubular. 
         FIG. 4  is a schematic of a wellbore from which a slot could be provided from a single wellbore in a formation. 
         FIG. 5  is a schematic of alternative embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION 
     Referring now to  FIG. 1 , a wellbore  101  with a horizontal U-shaped section  102  is shown. The wellbore has substantially vertical sections  103  extending from surface locations  104  where drilling rigs  105  are placed. The vertical sections extend through overburden  106  and into a target formation  107  that could contain hydrocarbons such as, for example, natural gas. The sections of the wellbores that extend through the overburden may be cased with casings  108  that are cemented into place. The U-shaped section  102  preferably has two essentially parallel legs  109 , connected by an essentially horizontal run  110 . In some embodiments, the legs  109  could be tilted up, so that any hydrocarbon liquids produced from the wellbore after the well is completed would flow down to a point close to the vertical sections where they could be produced, by for example, an electrical submersible pump. Tilting up of the legs  109  may also facilitate the removal of cuttings as the slot is formed since the circulating drilling fluid would tend to follow the shortest path between legs  109  which would be at the lowest point as the slot is formed and the cuttings would also tend to aggregate at that lowest point. In other embodiments, the legs  109  could be angled up or down so that the completed slotted wellbore could be sheared by horizontal formation stresses to help maintain the slot open. 
     Wellbores  101  are shown with sections  103  being essentially vertical, but they could enter the overburden angled, for example, at 45 degrees from vertical. Having the wellbores start out at an angle would reduce the friction between the formation and tubulars moving within the wellbore caused by the greater change in the direction of the wellbore to transition to a more horizontal orientation. The optimum angle of the wellbore entering from the surface could be estimated as a trade-off between the change in frictional forces and the increased length of vertical section  103  needed to reach the target formation  107 . 
     Most formations contain a direction in which most naturally occurring fractures occur. The U-shaped wellbore could be placed so that this plane,  111 , is essentially perpendicular to the longest dimension of the finished slot between the legs of the U-shaped wellbore. This would maximize the number of natural fractures intersected, and increase production of hydrocarbons from the finished wellbore. 
     The U-shaped wellbore could be, for example, constructed by starting two separate wells, and connecting the two wells by intersecting the two wellbores in the middle, at mid-point  112 . It would be very difficult to have the two wellbores lined up so that they intersect directly, but, for example, a magnetic device could be placed in the end of the first of the two wellbores to be provided, and the second could be directionally drilled toward the magnet, and the wellbores could be connected by intersecting the wellbores at a relatively small angle. The changes in direction shown in the figures are greatly exaggerated in order to show the entire well, but could be provided with changes in direction in the range of 10 to 15 degrees for each one hundred feet of the wellbore. This is well within the range of directional drilling systems used in the oil and gas industry. 
     Parallel legs  109 , and essentially horizontal run  110  could be left as open holes, or could be cased with a soft millable casing. 
     In another embodiment, parallel legs  109  could be placed in an essentially vertical plane and a vertical rather than a horizontal slot may be formed. 
     The initial borehole is referred to as U-shaped, but the shape could be significantly different. It is not intended that this description be literally applied. For example, two wellbores could approach each other at an angle rather than straight, and result in an initial borehole that is the shape of a V instead of U, so long as the cutting element could pass through the intersection of the wellbores. 
     The U-shaped well is drilled with conventional directional drilling techniques. The dimensions of the U-shaped well may be, in general, with the essentially parallel legs from 100 feet to two miles apart (31 meters to 3250 meters), or, for example, 500 to 2000 feet apart (154 meters to 615 meters). The total length of the U-shaped well is only limited by the distance the legs could be directionally drilled and intersected. With the total length of the U-shaped well limited, the ratio of the distance between the essentially parallel legs and the length of the essentially parallel legs may be between 1:1 and 5:1. T area of the final slot between the legs of the U-shaped section is maximized when the ratio of the distance between the parallel legs and the distance between the essentially parallel legs is 1:2. In other embodiments, a longer length of the parallel legs may also be useful because the resulting longer slotted well, if placed perpendicular to the direction of naturally occurring fractures, would intersect more naturally occurring fractures and therefore may more efficiently connect the wellbores to a larger volume of the formation. 
     The two drilling rigs  105 , when both are attached to the cutting element, would need to be operated in a coordinated manner. A distributed control system (“DCS”) might be utilized to coordinate this operation and optionally allow operation of both drilling rigs by one operator. Non-rotating casing protectors (“NRDPP”) may also be utilized to control wear of the casings and reduce torque and drag in sections of the wellbore not to be part of the slot to be created. NRDPPs are described in, for example, SPE Paper 76759 by Fuller and Jardaneh, the disclosure of which is incorporated herein by reference. 
     The motors could be hydraulic motors, and could be positive displacement hydraulic motors driven by a flow of drilling fluids. The motors could also be electrical motors such as the motor described in SPE paper 68441 by Head et al., or electrical motors similar to motors used in electrical submersible pumps. The motors may drive collars connected to cutting elements such as shearers similar to E-CTD type shearers, described in SPE paper 68441, SPE paper 52791 by Turner and et al, SPE paper 46013 by Head and et al. The number of shearing elements driven by each motor may be, for example, between one and one hundred, or between ten and fifty. More than one motor could be incorporated in the system. Electrical power could be provided by cables such as those used to power electrical submersible pumps. The cables could be placed inside the conduits for protection, and here may be multiple cables or multiple cables extending to each surface rig. The total power that could be provided to electrical motors for the present application could be sufficient to provide, for example, 1000 horse power to drive cutting elements. The motors described in SPE paper 68441 are claimed to be capable of producing up to 28 horsepower. Thirty or more of such motors could be provided along a string of motor and cutting elements. 
     Typically, in a drilling operation, drilling fluids are circulated to a drill bit through a drilling string, and the drilling fluids cool and transport rock cuttings back up the wellbore through an annular around the drilling string. A system like this conventional drilling system could be used. Alternatively, drilling fluid could be pumped down one vertical wellbore, through the U-shaped portion and back up the other wellbore. After the slot is at least partially created, the velocities of the drilling fluid may not be sufficient to remove all of the cuttings created. Cuttings remaining in the slot will not hinder subsequent hydrocarbon production because the slots will still have permeability orders of magnitude higher than the formation. 
     Referring now to  FIG. 2 , the U-shaped wellbore  201  is shown with slots  202  shown partially connecting two parallel legs,  203  and  204 , of the U-shaped wellbore. The slot may be formed by placing in the well cutting assemblies having motors driving cutting elements around the circumference of the motors, and pulling the cutting element back and forth through the wellbore while tension is maintained on the cutting element by, for example, connecting each end of the cutting element to drill strings, coiled tubing, bars such as the bars used for sucker rod pumps, or combinations thereof. Multiple slots are shown in  FIG. 2  although in some embodiments, a single slot may be provided connecting essentially the full length of the parallel legs  203  and  204 . Providing multiple slots may reduce the cost by eliminating some slot cutting, and may provide support and reduce the tendency of the slot to collapse. Instead of, or in addition to motors rotating the cutting assemblies, the cutting assemblies could be rotated from the surface. In general, coiled tubing could be advantageous because the operation could be more continuous and therefore proceed more rapidly. 
     Referring now to  FIG. 3 , a schematic drawing of a cutting assembly  301  is shown. Cutting elements  302  are shown positioned radially around a circumference of the cutting assembly. A motor  303  within the cutting assembly drives the cutting elements. End connections  304  connect the ends of the cutting assembly to, for example, coiled tubing or drill string elements  305 , the coiled tubing or drill string may also provide a protective conduit for electrical supply cables, and a path for drilling fluids into the cutting assembly, so that the drilling fluids may be directed at the cutting elements to transport cuttings from the cutting elements. The cutting assembly could also include logging instruments, or accelerometers to track the location of the cutting assembly. Output from the logging tools and/or accelerometers could be multiplexed and sent as a high frequency signal over the power supply cables to enable tracking of the progress of the operation. 
     The cutting assembly  301  could be assembled with high torque non-upset connections such as the TKC 4040 connection from Hunting Energy Services, 1018 Rankin Road, Houston, Tex., 77049. The cutting elements  302  could include wear resistant materials such as tungsten carbide, diamond impregnated elements or polycrystalline diamond cutters, and the cutting elements could be positioned along the length of the cutting assembly. The cutting elements could be spiraled along the cylindrical outer surface of the cutting assembly. When hydraulic motors are used, fluids such as drilling mud could be provided from each of the drilling rigs, and, for example, an internal plug between motors being driven from fluids coming from each direction could be provided. The cutting assembly  301  could be provided with nozzles to distribute drilling fluids provide from one or both of the drilling rigs along the length of the cutting assembly as necessary to remove cuttings and to cool the cutting surfaces. 
     Joint  306  connects two separate motors  303 , each of the two motors driving a separate set of cutting elements associated with that motor. The motors rotate the cutting elements in opposite directions,  307  and  308 , so that torque against the wall of the wellbore is counteracted by the two oppositely turning sets of elements. Motor torque may also be counterbalanced, in some embodiments, by providing motors that turn in opposite directions. 
     Power supply is provided from surface facilities through cable  309 . Commercially available power supplies useful, for example, for electrical submersible pumps, may be utilized. 
     The cutting elements may be biased against one portion of the wellbore by being held in tension by, for example, drill strings, rods, or coiled tubing attached to each end of the cutting assembly. 
     Torque from the cutting elements against the wall of the borehole may counter each other, by providing the cutting elements, or alternating sets of cutting elements, that turn in alternating directions. This would result in a more levelled and controllable slot being formed. The cutting elements could be provided to turn in opposite directions by having, for example, alternating motors turning in opposite directions, or alternating motors could be geared to turn the cutting elements in different directions, or individual or sets of cutting elements could be geared to rotate in opposite directions. 
     In some embodiments of the present invention, the carrier pipe could enhance or replace the cutting action from the electric motors by rotating the entire assembly up to the maximum torque capacity of the pipe, as currently done in directional drilling. In this embodiment, some or all of the cutting surfaces can be without a connection to a motor. 
     In some embodiments of the present invention, multiple horizontal U-shaped sections of wellbore could be provided from the same set of vertical wellbores. The U-shaped sections of wellbore could be provided in opposite directions at similar levels, or multiple levels of U-shaped sections of wellbore could be provided at different elevations in the same direction, or both. The U-shaped wellbores, and subsequent slotted wellbores, could be vertically displaced, for example, between 50 feet (15 meters) and 500 feet (154 meters), or between 70 feet (22 meters) and 200 feet (62 meters). 
     Now referring to  FIG. 4 , a vertical wellbore  401  with two horizontal legs,  402  and  403 , are shown. The horizontal legs could be created by side-tracking from the vertical section in essentially the same direction as a lower horizontal section, and drilling the side-tracked leg of the well to essentially horizontal, and then toward the lower section to intersect the lower section. The lower section could have been drilled into an upward direction so that the intersection comes at a relatively small angle. This angle may be less than forty five degrees, or in another embodiment, between three and twenty degrees. A cutting element could then be placed in the wellbore according to the present invention and rotated or rotated and reciprocated to form a slot between the two horizontal legs. The horizontal legs may be legs that have a horizontal component but extend outward from the wellbore  401  and then connect to form a loop around a section of the formation  404  that may be removed by the present invention to form a slot. The slot may be essentially vertical. Multiple essentially vertical slots may be formed from a single wellbore by forming pairs of essentially horizontal legs in different directions. In one embodiment, there may be two pairs of essentially horizontal legs provided in opposite directions, so that two slots may be formed where both slots are essentially perpendicular to the orientation of many naturally occurring fractures. In another embodiment, there may be, for example, four, six or eight pairs of essentially horizontal legs extending from the wellbore to provide four, six, or eight slots in the formation extending from the essentially vertical wellbore. 
     Referring now to  FIG. 5 , an embodiment of the present invention is shown where two essentially parallel wellbores,  502  and  503 , have been connected to form a section connecting the two parallel legs  504 . The essentially parallel wellbores could be vertical, horizontal, or between vertical and horizontal. Rotational power from the surface, or from motors within the wellbores, is utilized to wind a cutting element  501  around a pair of rotatable tubulars  504  and  506  and there by reciprocating the cutting element  501  between the two essentially parallel wellbores by rotating the tubular so that the cutting element is wrapping around one tubular  506  as it is unwrapping from the other rotatable tubular  505 . After the cutting element is essentially unwound from one rotatable tubular, the rotations are reversed and the cutting element is passed through the connecting section of the wellbore in the opposite direction. The rotatable tubular also maintains the cutting element in tension, and biased against the wall of the connecting section of the wellbore so that the cutting element forms a slot in the formation between the two essentially parallel wellbores. Using rotational power may reduce wear and abrasion experienced by tubulars  505  and  506 , and may reduce the tension on the cutting element. This embodiment may also eliminate a need to remove slack on the drill pipe which would reduce non-productive rig time.