Patent Publication Number: US-9845641-B2

Title: Method and system for laterally drilling through a subterranean formation

Description:
CROSS-REFERENCES TO RELATED APPLICATIONS 
     This application is a continuation of application Ser. No. 13/682,433, filed on Nov. 20, 2012, which is a continuation-in-part of U.S. Pat. No. 8,312,939, patent application Ser. No. 12/723,974, filed on Mar. 15, 2010, and issued on Nov. 20, 2012, which is a continuation application of U.S. Pat. No. 7,686,101, application Ser. No. 11/246,896, filed on Oct. 7, 2005, and issued on Mar. 30, 2010, which is a continuation-in-part of application Ser. No. 11/109,502, filed on Apr. 19, 2005, which is a continuation of U.S. Pat. No. 6,920,945, application Ser. No. 10/290,113, filed on Nov. 7, 2002, and issued on Jul. 26, 2005, which claims the benefit of Provisional Application No. 60/348,476, filed on Nov. 7, 2001, all of which patents and applications are hereby incorporated herein by reference in their entirety. 
    
    
     TECHNICAL FIELD 
     The present invention relates generally to a method and system for facilitating horizontal (also referred to as “lateral”) drilling into a subterranean formation surrounding a well casing. More particularly, the invention relates to an internally rotating nozzle that may be used to facilitate substantially horizontal drilling into a subterranean formation surrounding a well casing. 
     BACKGROUND 
     The rate at which hydrocarbons are produced from wellbores in subterranean formations is often limited by wellbore damage caused by drilling, cementing, stimulating, and producing. As a result, the hydrocarbon drainage area of wellbores is often limited, and hydrocarbon reserves become uneconomical to produce sooner than they would have otherwise, and are therefore not fully recovered. Similarly, increased power is required to inject fluids, such as water and CO 2 , and to dispose of waste water, into wellbores when a wellbore is damaged. 
     Formations may be fractured to stimulate hydrocarbon production and drainage from wells, but fracturing is often difficult to control and results in further formation damage and/or breakthrough to other formations. 
     Tight formations are particularly susceptible to formation damage. To better control damage to tight formations, lateral (namely, horizontal) completion technology has been developed. For example, guided rotary drilling with a flexible drill string and a decoupled downhole guide mechanism has been used to drill laterally into a formation, to thereby stimulate hydrocarbon production and drainage. However, a significant limitation of this approach has been severe drag and wear on drill pipe since an entire drill string must be rotated as it moves through a curve going from vertical to horizontal drilling. 
     Coiled tubing drilling (CTD) has been used to drill lateral drainage holes, but is expensive and typically requires about a 60 to 70 foot radius to maneuver into a lateral orientation. 
     High pressure jet systems, utilizing non-rotating nozzles and externally rotating nozzles with fluid bearings have been developed to drill laterally to bore tunnels (also referred to as holes or boreholes) through subterranean formations. Such jet systems, however, have failed due to the turbulent dissipation of jets in a deep, fluid-filled borehole, due to the high pressure required to erode deep formations, and, with respect to externally rotating nozzles, due to impairment of the rotation of the nozzle from friction encountered in the formation. 
     Accordingly, there is a need for methods and systems by which wellbore damage may be minimized and/or bypassed, so that hydrocarbon drainage areas and drainage rates may be increased, and the power required to inject fluids and dispose of waste water into wellbores may be reduced. 
     BRIEF SUMMARY OF THE INVENTION 
     According to the present invention, lateral (i.e., horizontal) wellbores are utilized to facilitate a more efficient sweep in secondary and tertiary hydrocarbon recovery fields, and to reduce the power required to inject fluids and dispose of waste water into wells. The horizontal drilling of lateral wellbores through a substantially vertical or horizontal well casing is facilitated by positioning in the well casing a shoe defining a passageway extending from an upper opening in the shoe through the shoe to a side opening in the shoe. A rod and casing mill assembly is then inserted into the well casing and through the passageway in the shoe until a casing mill end of the casing mill assembly abuts the well casing. The rod and casing mill assembly are then rotated until the casing mill end forms a perforation in the well casing. 
     A housing of an internally rotating nozzle is attached to a first or lower end of a hose in the well casing for facilitating fluid communication between the hose and an interior portion of the housing. The housing defines a gauge ring extending from an end thereof opposite the hose, and the internally rotating nozzle includes a rotor rotatably mounted within the housing so that the entire rotor is contained within the interior portion of the housing. The rotor includes at least two tangential jets recessed within the gauge ring and oriented off-center to generate torque to rotate the rotor, and the rotor further defines passageways for providing fluid communication between the interior portion of the housing and the jets. 
     A second or upper end of the hose in the well casing opposite the lower end of the hose is connected to tubing in fluid communication with pressure generating equipment, to thereby facilitate fluid communication between the pressure generating equipment, the hose, and the nozzle. 
     The internally rotating nozzle is pushed through the passageway and the perforation into the subterranean formation and the gauge ring is urged against the subterranean formation. High pressure fluid from the pressure generating equipment is passed through the tubing and the hose into the nozzle and ejected from the at least two tangential jets causing the nozzle to rotate and cut a tunnel in subterranean earth formation. 
     In a system of the invention, lateral drilling through a well casing and into a subterranean formation is facilitated by a shoe positioned at a selected depth in the well casing, the shoe defining a passageway extending from an upper opening in the shoe through the shoe to a side opening in the shoe. A rod is connected to a casing mill assembly for insertion into and through the well casing and through the passageway in the shoe until a casing mill end of the casing mill assembly abuts the well casing. A motor is coupled to the rod for rotating the rod and casing mill assembly until the casing mill end forms a perforation in the well casing. 
     The system further includes an internally rotating nozzle having a housing is attached to a first end of a hose for facilitating fluid communication between the hose and an interior portion of the housing, the housing defining a gauge ring extending from an end thereof opposite the hose. The internally rotating nozzle includes a rotor rotatably mounted within the housing so that the entire rotor is contained within the interior portion of the housing. The rotor includes at least two tangential jets recessed within the gauge ring and oriented off-center to generate torque to rotate the rotor, and the rotor further defines passageways for providing fluid communication between the interior portion of the housing and the jets. Tubing in fluid communication with pressure generating equipment is connected to a second end of the hose opposite the first end of the hose for facilitating fluid communication between the pressure generating equipment, the hose, and the nozzle. The gauge ring is adapted for being urged against the subterranean formation while the at least two tangential jets eject fluid into the subterranean formation for impinging upon and eroding the subterranean formation, to thereby cut a tunnel in subterranean earth formation. 
     The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiment disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which: 
         FIG. 1  is a cross-sectional elevation view of a well having a drilling shoe positioned therein; 
         FIG. 2  is a cross-sectional elevation view of the well of  FIG. 1  having a perforation mechanism embodying features of the present invention positioned within the drilling shoe; 
         FIG. 3  is a cross-sectional elevation view of the well of  FIG. 2  showing the well casing perforated by the perforation mechanism; 
         FIG. 4  is a cross-sectional elevation view of the well of  FIG. 3  with the perforation mechanism removed; 
         FIG. 5  is a cross-sectional elevation view of the well of  FIG. 4  showing a hydraulic drilling device extended through the casing of the well; 
         FIG. 6  is a cross-sectional elevation view of the nozzle of  FIG. 5 ; 
         FIG. 7  is a elevation view taken along the line  7 - 7  of  FIG. 6 ; 
         FIG. 8  is a cross-sectional elevation view of an alternative embodiment of the nozzle of  FIG. 6  with brakes; 
         FIG. 9  is a cross-sectional elevation view taken along the line  9 - 9  of  FIG. 8 ; 
         FIG. 10  is a cross-sectional elevation view of an alternative embodiment of the nozzle of  FIG. 8  that further includes a center nozzle; and 
         FIG. 11  is an elevation view taken along the line  11 - 11  of  FIG. 10 . 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     In the discussion of the FIGURES the same reference numerals will be used throughout to refer to the same or similar components. In the interest of conciseness, various other components known to the art, such as wellheads, drilling components, motors, and the like necessary for the operation of the wells, have not been shown or discussed except insofar as necessary to describe the present invention. Additionally, as used herein, the term “substantially” is to be construed as a term of approximation. 
     Referring to  FIG. 1  of the drawings, the reference numeral  10  generally designates an existing well encased by a well casing  12  and cement  14 . While the well  10  is depicted as a substantially vertical well, it could alternatively be a substantially horizontal well (in which case  FIG. 1  would be treated similarly as a top or plan view rather than an elevation view) or it could be formed at any desirable angle. The well  10  passes through a subterranean formation  16  from which petroleum is drawn. A drilling shoe  18  is securely attached to a tubing  20  via a tapered threaded fitting  22  formed between the tubing  20  and the shoe  18 . The shoe  18  and tubing  20  are defined by an outside diameter approximately equal to the inside diameter of the well casing  12  less sufficient margin to preclude jamming of the shoe  18  and tubing  20  as they are lowered through the casing  12 . The shoe  18  further defines a passageway  24  which extends longitudinally through the shoe, and which includes an upper opening  26  and a lower opening  28 . The passageway  24  defines a curved portion having a radius of preferably at least three inches. The upper opening  26  preferably includes a limit chamfer  27  and an angle guide chamfer  29 , for receiving a casing mill, described below. 
     As shown in  FIG. 1 , the shoe  18  is lowered in the well  10  to a depth suitable for tapping into a hydrocarbon deposit (not shown), and is angularly oriented in the well  10  using well-known techniques so that the opening  28  of the shoe  18  is directed toward the hydrocarbon deposit. The shoe  18  is fixed in place by an anchoring device  25 , such as a conventional packer positioned proximate to a lower end  18   a  of the shoe  18 . While the anchoring device  25  is shown in  FIG. 1  as positioned proximate to the lower end  18   a  of the show  18 , the anchoring device is preferably positioned above, or alternatively, below the shoe. 
       FIG. 2  depicts the insertion of a rod  30  and casing mill assembly  32  as a single unit through the tubing  20  and into the passageway  24  of the shoe  18  for perforation of the well casing  12 . The rod  30  preferably includes an annular collar  34  sized and positioned for seating in the chamfer  27  upon entry of the casing mill  32  in the cement  14 , as described below with respect to  FIG. 3 . The rod  30  further preferably includes, threadingly connected at the lower end of the rod  30 , a yoke adapter  37  connected to a substantially barrel-shaped (e.g., semi-spherical or semi-elliptical) yoke  36  via a substantially straight yoke  38  and two conventional block and pin assemblies  39  operative as universal joints. The barrel-shaped yoke  36  is connected to a similar substantially barrel-shaped yoke  40  via a substantially straight yoke  42  and two conventional block and pin assemblies  43  operative as universal joints. Similarly, the barrel-shaped yoke  40  is connected to a substantially barrel-shaped yoke  44  via a substantially straight yoke  46  and two conventional block and pin assemblies  47  operative as universal joints. Similarly, the barrel-shaped yoke  44  is connected to a substantially barrel-shaped “half” yoke  48  via a conventional block and pin assembly  49  operative as a universal joint. The surfaces of the yokes  36 ,  40 ,  44 , and  48  are preferably barrel-shaped so that they may be axially rotated as they are passed through the passageway  24  of the shoe  18 . The yoke  48  includes a casing mill end  48   a  preferably having, for example, a single large triangular-shaped cutting tooth (shown), a plurality of cutting teeth, or the like, effective upon axial rotation for milling through the well casing  12  and into the cement  14 . The milling end  48   a  is preferably fabricated from a hardened, high strength, stainless steel, such as 17-4 stainless steel with tungsten carbides inserts, tungsten carbide, or the like, having a relatively high tensile strength of, for example, at least 100,000 pounds per square inch, and, preferably, at least 150,000 pounds per square inch. While four substantially barrel-shaped yokes  36 ,  40 ,  44 , and  48 , and three substantially straight yokes  38 ,  42 ,  46 , are shown and described with respect to  FIG. 2 , more or fewer yokes may be used to constitute the casing mill assembly  32 . 
     The rod  30  is preferably connected at the well-head of the well  10  to a rotating device, such as a motor  51 , effective for generating and transmitting torque to the rod  30  to thereby impart rotation to the rod. The torque transmitted to the rod  30  is, by way of example, from about 25 to about 1000 foot-pounds of torque and, typically, from about 100 to about 500 foot-pounds of torque and, preferably, is about 200 to about 400 foot-pounds of torque. The casing mill assembly  32  is preferably effective for transmitting the torque and rotation from the rod  30  through the passageway  24  to the casing mill end  48 . 
     In operation, the tubing  20  and shoe  18  are lowered into the well casing  12  and secured in position by an anchoring device  25 , as described above. The rod  30  and casing mill assembly  32  are then preferably lowered as a single unit through the tubing  20  and guided via the angle guide chamfer  29  into the shoe  18 . The motor  51  is then coupled at the well-head to the rod  30  for generating and transmitting preferably from about 100 to about 400 foot-pounds of torque to the rod  30 , causing the rod  30  to rotate. As the rod  30  rotates, it imparts torque and rotation to and through the casing mill assembly  32  to rotate the casing mill end  48 . 
     The weight of the rod  30  also exerts downward axial force in the direction of the arrow  50 , and the axial force is transmitted through the casing mill assembly  32  to the casing mill end  48 . The amount of weight transmitted through the casing mill assembly  32  to the casing mill end  48  may optionally be more carefully controlled to maintain substantially constant weight on the casing mill end  48  by using weight bars and bumper subs (not shown). As axial force is applied to move the casing mill end  48  into the well casing  12  and cement  14 , and torque is applied to rotate the casing mill end  48 , the well casing  12  is perforated, and the cement  14  is penetrated, as depicted in  FIG. 3 . The weight bars are thus suitably sized for efficiently perforating the well casing  12  and penetrating the cement  14  and, to that end, may, by way of example, be sized at 150 pounds each, it being understood that other weights may be preferable depending on the well. Weight bars and bumper subs, and the sizing thereof, are considered to be well known in the art and, therefore, will not be discussed in further detail herein. 
     As the casing mill end  48  penetrates the cement  14 , the collar  34  seats in the chamfer  27 , and the perforation of the well casing is terminated. The rod  30  and casing mill assembly  32  are then withdrawn from the shoe  18 , leaving a perforation  52 , which remains in the well casing  12 , as depicted in  FIG. 4 . Notably, the cement  14  is preferably not completely penetrated. To obtain fluid communication with the petroleum reservoir/deposit of interest, a horizontal extension of the perforation  52  is used, as discussed below with respect to  FIG. 5 . 
       FIG. 5  depicts a horizontal extension technique that may be implemented for extending the perforation  52  ( FIG. 4 ) laterally into the formation  16  in accordance with present invention. The shoe  18  and tubing  20  are maintained in place. A flexible hose  62 , having a nozzle  64  affixed to a lower end thereof, is extended through the tubing  20 , the guide chamfer  29  and passageway  24  of the shoe  18 , and the perforation  52  into the cement  14  and subterranean formation  16 . The hose  62  is preferably only used in a lower portion of the well  10  as necessary for passing through the shoe  18  and into the formation  16 , and high-pressure jointed tubing or coil tubing (not shown) is preferably used in an upper portion of the well for coupling the hose  62  to equipment  67  at the surface of the well, as discussed below. The flexible hose  62  is preferably a high-pressure (e.g., tested for a capacity of 20,000 PSI or more) flexible hose, such as a Polymide 2400 Series hose, preferably capable of passing through a curve having a radius of three inches. The hose  62  is preferably circumscribed by a spring  66  preferably comprising spiral wire having a square cross-section which abuts the nozzle  64  at a first or lower end of the hose and the tubing (e.g., a ring at a lower end of the tubing, not shown) at a second or upper end of the hose for facilitating “pushing” the hose  62  downwardly through the tubing  20 . The spring  66  may alternatively comprise spiral wire having a round cross-section. The nozzle  64  is a high-pressure rotating nozzle, as described in further detail below with respect to  FIGS. 6-10 . A plurality of annular guides, referred to herein as centralizers,  68  are preferably positioned about the spring  66  and suitably spaced apart for inhibiting bending and kinking of the hose  62  within the tubing  20 . Each centralizer  68  has a diameter that is substantially equal to or less than the inside diameter of the tubing  20 , and preferably also defines a plurality of slots and/or holes  68   a  for facilitating the flow of fluid through the tubing  20 . The centralizers  68  are preferably also configured to slide along the spring  66  and rest and accumulate at the top of the shoe  18  as the hose  62  is pushed through the passageway  24  and perforation  52  into the formation  16 . 
     Drilling fluid is then pumped at high pressure preferably via jointed tubing or coil tubing (not shown) through the hose  62  to the nozzle  64  using conventional pressure generating equipment  67  (e.g., a compressor, a pump, and/or the like) at the surface of the well  10 . The drilling fluid used may be any of a number of different fluids effective for eroding subterranean formation, such fluids comprising liquids, solids, and/or gases including, by way of example but not limitation, one or a mixture of two or more of fresh water, produced water, polymers, water with silica polymer additives, surfactants, carbon dioxide, gas, light oil, methane, methanol, diesel, nitrogen, acid, and the like, which fluids may be volatile or non-volatile, compressible or non-compressible, and/or optionally may be utilized at supercritical temperatures and pressures. The drilling fluid is preferably injected through the hose  62  and ejected from the nozzle  64 , as indicated schematically by the arrows  66 , to impinge subterranean formation material. The drilling fluid loosens, dissolves, and erodes portions of the earth&#39;s subterranean formation  16  around the nozzle  64 . The excess drilling fluid flows into and up the well casing  12  and tubing  20 , and may be continually pumped away and stored. As the earth  16  is eroded away from the frontal proximity of the nozzle  64 , a tunnel (also referred to as an opening or hole)  70  is created, and the hose  62  is extended into the tunnel. The tunnel  70  may generally be extended laterally 200 feet or more to insure that a passageway extends and facilitates fluid communication between the well  10  and the desired petroleum formation in the earth&#39;s formation  16 . 
     After a sufficient tunnel  70  has been created, additional tunnels may optionally be created, fanning out in different directions at substantially the same level as the tunnel  70  and/or different levels. If no additional tunnels need to be created, then the flexible hose  62  is withdrawn upwardly from the shoe  18  and tubing  20 . The tubing  20  is then pulled upwardly from the well  10  and, with it, the shoe  18 . Excess drilling fluid is then pumped from the well  10 , after which petroleum product may be pumped from the formation. 
       FIG. 6  depicts one preferred embodiment of the nozzle  64  in greater detail positioned in the tunnel  70 , the tunnel having an aft portion  70   a  and a fore portion  70   b . As shown therein, the nozzle  64  includes a hose fitting  72  configured for being received by the hose  62 . In a preferred embodiment, the hose fitting  72  also includes circumferential barbs  72   a  and a conventional band  73  clamped about the periphery of the hose  62  for securing the hose  62  onto the hose fitting  72  and barbs  72   a.    
     The hose fitting  72  is threadingly secured to a housing  74  of the nozzle  64  via threads  75 , and defines a passageway  72   b  for providing fluid communication between the hose  62  and the interior of the housing  74 . A seal  76 , such as an O-ring seal, is positioned between the hose fitting  72  and the housing  74  to secure the housing  74  against leakage of fluid received from the hose  62  via the hose fitting  72 . The housing  74  is preferably fabricated from a stainless steel, and preferably includes a first section  74   a  having a first diameter, and a second section  74   b , also referred to as a gauge ring, having a second diameter of about 2-20% larger than the first diameter, and preferably about 10% larger than the first diameter. While the actual first and second diameters of the housing  74  are scalable, by way of example and not limitation, in one preferred embodiment, the second diameter is about 1-1.5 inches in diameter, and preferably about 1.2 inches in diameter. About eight drain holes  74   c  are preferably defined between the first and second sections  74   a  and  74   b  of the housing  74 , for facilitating fluid communication between the aft portion  70   a  and the fore portion  70   b  of the tunnel  70 . The number of drain holes  74   c  may vary from eight, and accordingly may be more or less than eight drain holes. 
     A rotor  84  is rotatably mounted within the interior of the housing  74  so that the entire rotor is contained within the interior of the housing, and includes a substantially conical portion  84   a  and a cylindrical portion  84   b . The conical portion  84   a  includes a vertex  84   a ′ directed toward the hose fitting  72 . The cylindrical portion  84   b  includes an outside diameter approximately equal to the inside diameter of the housing  74  less a margin sufficient to avoid any substantial friction between the rotor  84  and the housing  74 . The cylindrical portion  84   b  abuts a bearing  78 , preferably configured as a thrust bearing, and race  88 , which seat against an end of the housing  74  opposed to the hose fitting  72 . The thrust bearing  78  is preferably a carbide ball bearing, and the race  88  is preferably fabricated from carbide as well. A radial clearance seal (not shown) may optionally be positioned between the rotor  84  and the bearing race  88  to minimize fluid leakage through the bearing  78 . A center extension portion  84   c  of the rotor  84  extends from the cylindrical portion  84   b  through the thrust bearings  78  and race  88 , and two tangential jets  84   d  are formed on the rotor center extension portion  84   c  and recessed within the gauge ring  74   b . Each jet  84   d  is configured to generate a jet stream having a diameter of about 0.025 to 0.075 inches, and preferably about 0.050″. Passageways  84   e  are defined in the rotor  84  for facilitating fluid communication between the interior of the housing  74  and the jets  84   d.    
     As shown most clearly in  FIG. 7 , the tangential jets  84   d  are offset from a center point  84   f  and are directed in substantially opposing directions, radially spaced from, and tangential to, the center point  84   f . Referring back to  FIG. 6 , the jets  84   d  are preferably further directed at an angle  91  of about 45° from a centerline  84   g  extending through the rotor  84  from the vertex  84   a  through the center point  84   f.    
     Further to the operation described above with respect to  FIGS. 1-5 , and with reference to  FIGS. 6 and 7 , fluid is pumped down and through the hose  62  at a flow rate of about 15 to 25 gallons per minute (GPM), preferably about 20 GPM, and a pressure of about 10,000 to 20,000 pounds per square inch (PSI), preferably about 15,000 PSI. The fluid passes through the passageway  72   b  into the interior of the housing  74 . The fluid then passes into and through the passageways  84   e  to the jets  84   d , and is ejected as a coherent jet stream of fluid  90  from the jets  84   c  at an angle  91  from the centerline  84   g . The jet stream of fluid  90  impinges and erodes earth in the fore portion  70   b  of the tunnel  70 . A tangential component of the stream of fluid  90  ( FIG. 7 ) causes the rotor  84  to rotate in the direction of an arrow  85  at a speed of about 40,000 to 60,000 revolutions per minute (RPM), though a lower RPM are generally preferred, as discussed in further detail below with respect to  FIGS. 8-11 . As the rotor  84  rotates, the stream of fluid  90  rotates, further impinging and eroding a cylindrical portion of earth in the fore portion  70   b  of the tunnel  70 , thereby extending longitudinally the tunnel  70 . As earth is eroded, it mixes with the fluid, drains away through the holes  74   c , passes through the aft portion  70   a  of the tunnel  70 , and then flows upwardly through and out of the well  10 . The nozzle  64  is then urged via the hose  62  toward the fore portion  70   b  of the tunnel  70  to extend the tunnel  70  as a substantially horizontal portion of the well  10 . 
       FIGS. 8 and 9  depict the details of a nozzle  100  according to an alternate embodiment of the present invention. Since the nozzle  100  contains many components that are identical to those of the previous embodiment ( FIGS. 6-7 ), these components are referred to by the same reference numerals, and will not be described in any further detail. According to the embodiment of  FIGS. 8 and 9 , a brake lining  102  extends along, and is substantially affixed to, the interior peripheral surface of the housing  74 . The brake lining  102  is preferably fabricated from a relatively hard material, such as hardened carbide steel. Two or more brake pads  104 , likewise fabricated from a relatively hard material, such as hardened carbide steel, are positioned within mating pockets defined between the rotor  84  and the brake lining  102 , wherein the pockets are sized for matingly retaining the brake pads  104  proximate to the brake lining  102  so that, in response to centrifugal force, the brake pads  104  are urged and moved radially outwardly to frictionally engage the brake lining  102  as the rotor  64  rotates. 
     Operation of the nozzle  100  is similar to the operation of the nozzle  64 , but for a braking effect imparted by the brake lining  102  and brake pads  104 . More specifically, as the rotor  84  rotates, centrifugal force is generated which is applied onto the brake pads  104 , urging and pushing the brake pads  104  outwardly until they frictionally engage the brake lining  102 . It should be appreciated that as the rotor  84  rotates at an increasing speed, or RPM, the centrifugal force exerted on the brake pads  104  increases in proportion to the square of the RPM, and resistance to the rotation thus increases exponentially, thereby limiting the maximum speed of the rotor  84 , without significantly impeding rotation at lower RPM&#39;s. Accordingly, in a preferred embodiment, the maximum speed of the rotor will be limited to the range of about 1,000 RPM to about 50,000 RPM, and preferably closer to 1,000 RPM (or even lower) than to 50,000 RPM. It is understood that the centrifugal force generated is, more specifically, a function of the product of the RPM squared, the mass of the brake pads, and radial distance of the brake pads from the centerline  84   g . The braking effect that the brake pads  104  exert on the brake lining  102  is a function of the centrifugal force and the friction between the brake pads  104  and the brake lining  102 , and, furthermore, is considered to be well known in the art and, therefore, will not be discussed in further detail herein. 
       FIG. 10  depicts the details of a nozzle  110  according to an alternate embodiment of the present invention. Since the nozzle  110  contains many components that are identical to those of the previous embodiments ( FIGS. 6-9 ), these components are referred to by the same reference numerals, and will not be described in any further detail. According to the embodiment of  FIG. 10 , and with reference also to  FIG. 11 , an additional center jet  84   h , preferably smaller than (e.g., half the diameter of) the tangential jets  84   d , is configured in the center extension portion  84   c  of the rotor  84 , interposed between the two tangential jets  84   d  for ejecting a jet stream  112  of fluid along the centerline  84   g.    
     Operation of the nozzle  110  is similar to the operation of the nozzle  100 , but for providing an additional jet stream of fluid from the center jet  84   h , effective for cutting the center of the tunnel  70 . 
     By the use of the present invention, a tunnel may be cut in a subterranean formation in a shorter radius than is possible using conventional drilling techniques, such as a slim hole drilling system, a coiled tube drilling system, or a rotary guided short radius lateral drilling system. Even compared to ultra-short radius lateral drilling systems, namely, conventional water jet systems, the present invention generates a jet stream which is more coherent and effective for cutting a tunnel in a subterranean formation. Furthermore, by utilizing bearings, the present invention also has less pressure drop in the fluid than is possible using conventional water jet systems. 
     It is understood that the present invention may take many forms and embodiments. Accordingly, several variations may be made in the foregoing without departing from the spirit or the scope of the invention. For example, the conical portion  84   a  of the rotor  84 , or a portion thereof, may be inverted to more efficiently capture fluid from the hose  62 . The brake pads  104  ( FIG. 9 ) may be tapered to reduce resistance from, and turbulence by, fluid in the interior of the housing  74  as the rotor  84  is rotated. The thrust bearing  78  may comprise types of bearings other than ball bearings, such as fluid bearings. 
     Having thus described the present invention by reference to certain of its preferred embodiments, it is noted that the embodiments disclosed are illustrative rather than limiting in nature and that a wide range of variations, modifications, changes, and substitutions are contemplated in the foregoing disclosure and, in some instances, some features of the present invention may be employed without a corresponding use of the other features. Many such variations and modifications may be considered obvious and desirable by those skilled in the art based upon a review of the foregoing description of preferred embodiments. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention.