Patent Publication Number: US-11391094-B2

Title: Hydraulic drilling systems and methods

Description:
FIELD 
     This invention pertains generally to hydraulic drilling systems and methods and, more particularly, to systems and methods for performing various borehole drilling, earth measurement, and earth manipulation operations down hole. 
     BACKGROUND 
     U.S. Pat. No. 1,865,853 relates to the forming of boreholes from an existing wellbore by mechanical means to place a borehole tangentially from an existing wellbore using a rotational bit. Since then, many methods and systems in this area employ hose and nozzle technology to form the boreholes. However, these methods and systems fail to address a number of issues with the process of hydraulically forming boreholes from an existing wellbore. 
     First, to drill multiple boreholes in different orientations from the same axial location within an existing wellbore, whether the wellbore is vertical, horizontal or deviated, the work string must be rotated from surface using a rig. This process can be time consuming and expensive. 
     Second, when hydraulic pressure is applied to the work string, the pressure can cause the work string to lengthen due to piston force and shorten due to ballooning. Either of these conditions can be the dominate condition during the same operation depending on the pressure applied. If the pressure is varied during operations, the whipstock attached to the end of the work string can move axially in the wellbore. This axial movement can cause the drill string to be subject to additional bending and friction to remain in the borehole. If the movement is extreme the drill string can be caught in the borehole and potentially be broken off, thereby necessitating an expensive and time consuming retrieval process. 
     Third, the earth through which the borehole is to be placed is sometimes covered by well casing or liner and the casing or liner must be penetrated to extend the borehole into the earth. Conventional technology does not provide a one-step process for penetrating the casing or liner and placing a borehole. 
     Fourth, there is limited disclosure in the prior art about the potential uses for the boreholes. More specifically, many existing publications place great emphasis on borehole placement procedures and on the fluid used during the borehole placement process, but do not discuss what the borehole could be used for. 
     Fifth, existing technologies do not address the orientation and layout of multiple boreholes. It is conventional to place boreholes in vertical wells, which provides very little variety for borehole placement. Many new wells are deviated, horizontal or nearly horizontal, and these wells can stretch extended distances into the earth. The strategic placement of boreholes into these new wells may improve production and enhance the distribution of injection substances. 
     SUMMARY OF THE INVENTION 
     In accordance with a broad aspect of the present invention, there is provided a hydraulic drilling system for placement of boreholes for a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore and a rotational device engaged to the proximate end of the first work string, and the position of the upper section is fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; an activatable anchor for engaging the inner surface of the wellbore when activated to anchor the whipstock; a second work string that is extendable and contractible in an axial direction of the first work string, the second work string forms a length of the first work string at an axial location between the proximate end and the distal end of the first work string, for accommodating at least a portion of any axial forces on the first work string; a movement control device; and a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, the advancement and retraction of the drill tubing relative to the whipstock being controlled by the movement control device, the rotational device is activate-able to rotate the whipstock, via the first work string, about a central long axis of the first work string, for repositioning the whipstock exit radially relative to the long central axis, and the drill tubing allowing fluid to pass therethrough via the upper section. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface and at least one borehole extending radially therefrom, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string, and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, and the drill tubing allowing fluid to pass therethrough via the upper section; and a positional measurement device for determining the location of one or more of: the at least one borehole, the whipstock exit, and the distal end of the drill tubing. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; a drill tubing extending inside the first work string, defining an annulus therebetween, and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, and the drill tubing allowing fluid to pass therethrough via the upper section; a lower seal for fluidly sealing the interface between the drill tubing and the whipstock inner bore; and a passage through the lower seal allowing fluid communication between the annulus and the whipstock. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, and the drill tubing allowing fluid to pass therethrough via the upper section; and a lower seal for fluidly sealing the interface between the drill tubing and the whipstock inner bore, the lower seal having an inner bore, through which a portion of the drill tubing is extendible, and the distal end of the drill tubing is sized to have an overall diameter greater than the diameter of the lower seal inner bore. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit having an inner diameter and a deflection assembly having an inner bore providing a passage from the bore of the first work string to the whipstock exit, the inner bore of the deflection assembly having an inner diameter; and a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, a portion of the drill tubing being extended through the inner bore of the deflection assembly with the distal end extended through and outside the inner bore of the deflection assembly, the inner bore of the deflection assembly for guiding the drill tubing towards the whipstock exit as the drill tubing advances therethrough; and the distal end of the drill tubing is sized to have an overall diameter greater than the inner diameter of the inner bore of the deflection assembly. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, and the drill tubing allowing fluid to pass therethrough via the upper section; and a plurality of acoustic sensors installed near the distal end of the first work string for sensing sound of fluid exiting the opening of the drill tubing and generating data signals for calculating the location of the distal end of the drill tubing. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, and the drill tubing allowing fluid to pass therethrough via the upper section; a magnetic source installed at the distal end of the drill tubing, the magnetic source having a magnetic field; and a plurality of magnetic sensors installed near the distal end of the first work string for sensing the magnetic field of the magnetic source and generating data signals for calculating the location of the distal end of the drill tubing. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, the drill tubing allowing fluid to pass therethrough via the upper section; at least one selectively openable side port at or near the distal end of the drill tubing, and when the at least one side port is open and a fluid from the drill tubing passes through therethrough, a high pressure fluid jet is generated and is sufficient to steer the distal end of the drill tubing in a direction away from the exit direction of the high pressure fluid jet; and a positional device installed in the drill tubing for controlling the opening and closing the at least one side port. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; a movement control device; a pair of swivels between which the whipstock is mounted, thereby allowing the whipstock to rotate freely about its long central axis; and a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, the advancement and retraction of the drill tubing relative to the whipstock being controlled by the movement control device, and the drill tubing allowing fluid to pass therethrough via the upper section. 
     In accordance with another broad aspect of the present invention, there is provided a hydraulic drilling system for use with a wellbore having an inner surface, the system comprising: a first work string for placement down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end; an upper section having an inner bore, the upper section being engaged to the proximate end of the first work string and the position of the upper section being fixed relative to the wellbore; a whipstock provided at the distal end of the first work string, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; a movement control device; wheels or treads on an outer surface of the whipstock for frictionally engaging the inner surface of the wellbore; a drive mechanism coupled to the whipstock for driving the wheels or treads; and a drill tubing extending inside the first work string and having an inner bore leading to an opening at a distal end of the drill tubing, and the drill tubing being extendable through the inner bore of the whipstock, such that with the opening is extendable through the whipstock exit, the advancement and retraction of the drill tubing relative to the whipstock being controlled by the movement control device, the whipstock being selectively actively conveyable in an axial direction relative to the wellbore by operation of the drive mechanism, and the drill tubing allowing fluid to pass therethrough via the upper section. 
     In accordance with another broad aspect of the present invention, there is provided a method of hydraulic drilling in a wellbore comprising: running a first work string down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end, the proximate end of the first work string being engaged to an upper section having an inner bore, the position of the upper section being fixed relative to the wellbore, the distal end of the first work string having a whipstock, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit, the whipstock being coupled to a rotational device activatable to rotate the whipstock about a central long axis of the first work string, and the first work string including a second work string that forms a length thereof, the second work string being between the proximate end and the distal end of the first work string, and being extendable and contractible in an axial direction of the first work string for accommodating at least a portion of any forces in the axial direction; extending a drill tubing inside the first work string, the drill tubing having an inner bore leading to an opening at a distal end of the drill tubing; inserting at least a portion of the drill tubing through the whipstock; anchoring the first work string against an inner surface of the wellbore; and introducing pressurized drilling fluid into the drill tubing and discharging the fluid through the opening of the drill tubing. 
     In accordance with another broad aspect of the present invention, there is provided a method of obtaining location data in a wellbore comprising: running a first work string down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end, the proximate end of the first work string being engaged to an upper section having an inner bore, the position of the upper section being fixed relative to the wellbore, the distal end of the first work string having a whipstock, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; extending a drill tubing inside the first work string, the drill tubing having an inner bore leading to an opening at a distal end of the drill tubing; and determining the location of one or more of: a borehole, the whipstock exit, and the distal end of the drill tubing, using a positional measurement device. 
     In accordance with another broad aspect of the present invention, there is provided a method of hydraulic drilling in a wellbore comprising: running a first work string down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end, the proximate end of the first work string being engaged to an upper section having an inner bore, the position of the upper section being fixed relative to the wellbore, the distal end of the first work string having a whipstock, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; extending a drill tubing inside the first work string, the drill tubing having an inner bore leading to a rotatable drill head at a distal end of the drill tubing, the drill head providing an opening in communication with the inner bore of the drill tubing; inserting at least a portion of the drill tubing through the whipstock; introducing pressurized drilling fluid into the drill tubing; and ejecting the pressurized drilling fluid from the drill head and rotating the drill head, thereby cutting a borehole from the inner surface of the wellbore and allowing the drill head to advance into the borehole. 
     In accordance with another broad aspect of the present invention, there is provided a method of hydraulic drilling in a substantially horizontal wellbore comprising: running a first work string down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end, the proximate end of the first work string being engaged to an upper section having an inner bore, the position of the upper section being fixed relative to the wellbore, the distal end of the first work string having a whipstock, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; extending a drill tubing inside the first work string, the drill tubing having an inner bore leading to an opening at a distal end of the drill tubing; inserting at least a portion of the drill tubing through the whipstock; anchoring the first work string against an inner surface of the wellbore; introducing pressurized drilling fluid into the drill tubing and discharging the fluid through the opening of the drill tubing; cutting a first hole from the inner surface of the wellbore at a first preselected location of the wellbore with the pressurized drilling fluid exiting from the opening of the drill tubing, thereby allowing the distal end of the drill tubing to advance through the first hole; forming a first borehole extending from the first hole with the pressurized drilling fluid, the first borehole having a preselected length and a preselected trajectory; cutting a second hole from the inner surface of the wellbore at a second preselected location of the wellbore with the pressurized drilling fluid exiting from the opening of the drill tubing, thereby allowing the distal end of the drill tubing to advance through the second hole; and forming a second borehole extending from the second hole with the pressurized drilling fluid, the second borehole having a preselected length and a preselected trajectory, and wherein the first and second boreholes extend radially outwardly from the wellbore when viewed from one end of the wellbore, wherein (i) the first and second boreholes are spaced apart axially along the length of the wellbore; and/or (ii) the first and second boreholes define a radial angle therebetween when viewed from one end of the wellbore, and the angle is between about 0 degrees and about 180 degrees. 
     In accordance with another broad aspect of the present invention, there is provided a method of obtaining measurements in a wellbore comprising: running a first work string down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end, the proximate end of the first work string being engaged to an upper section having an inner bore, the position of the upper section being fixed relative to the wellbore, the distal end of the first work string having a whipstock, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; extending a drill tubing inside the first work string, the drill tubing having an inner bore leading to an opening at a distal end of the drill tubing; inserting at least a portion of the drill tubing through the whipstock; anchoring the first work string against an inner surface of the wellbore; introducing pressurized drilling fluid into the drill tubing and discharging the fluid through the opening of the drill tubing; cutting a borehole from the inner surface of the wellbore with the pressurized drilling fluid exiting from the opening of the drill tubing, thereby allowing the distal end of the drill tubing to advance into the borehole; placing at least one earth measurement device in one or more of: the whipstock, the drill tubing, the borehole, and surrounding earth of the borehole; and taking measurements using the at least one earth measurement device. 
     In accordance with another broad aspect of the present invention, there is provided a method of earth manipulation in a borehole extending radially from a wellbore, the borehole having a proximate end at an inner surface of the wellbore and a distal end away from the wellbore, and earth surrounding the distal end of the borehole having an initial temperature, permeability, porosity, and rock wettability, the method comprising: extending a drill tubing inside the wellbore, the drill tubing having an inner bore leading to an opening at a distal end of the drill tubing; inserting the opening of the drill tubing into the borehole and positioning the opening of the drill tubing at or near the distal end of the borehole; supplying a fluid into the drill tubing and discharging the fluid through the opening of the drill tubing, the fluid having a temperature lower from the initial temperature, thereby changing the initial temperature to a new temperature; and ceasing the supply of the fluid in the drill tubing to allow the earth to return to the initial temperature. 
     In accordance with another broad aspect of the present invention, there is provided a method of hydraulic fracturing in a borehole extending radially from a wellbore having an inner surface, the borehole having a proximate end at an inner surface of the wellbore, a distal end away from the wellbore, and earth surrounding the borehole, the method comprising: running a first work string down the wellbore, the first work string having an outer surface, inner surface defining an axially extending bore, a proximate end, and a distal end, the proximate end of the first work string being engaged to an upper section having an inner bore, the position of the upper section being fixed relative to the wellbore, the distal end of the first work string having a whipstock, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit, the outer surface of the first work string and the inner surface of the casing defining an annulus; extending a drill tubing inside the first work string, the drill tubing having an inner bore leading to an opening at a distal end of the drill tubing, at least a portion of the drill tubing extending through the whipstock; inserting the distal end of the drill tubing inside the borehole, via the whipstock exit; fluidly sealing at least a portion of the annulus, the at least a portion of the annulus in fluid communication with the borehole, thereby preventing fluid from exiting the wellbore; and generating or augmenting fractures in the earth surrounding the borehole by supplying a pressurized fluid into the drill tubing and injecting the pressurized fluid into the borehole through the opening of the drill tubing. 
     In accordance with another broad aspect of the present invention, there is provided a method of earth manipulation in a borehole extending radially from a wellbore, the borehole having a proximate end at an inner surface of the wellbore and a distal end away from the wellbore, and earth surrounding the borehole having an initial temperature, the method comprising: placing an earth manipulation device into the borehole, the earth manipulation device being one or more of: a resistive heating element, a microwave generating device, and an antenna; and activating the earth manipulation device to heat the earth to a new temperature that is higher than the initial temperature. 
     In accordance with another broad aspect of the present invention, there is provided a method of hydraulic drilling in a wellbore having a casing comprising: running a first work string down the wellbore, the first work string having an inner surface defining an axially extending bore, a proximate end, and a distal end, the proximate end of the first work string being engaged to an upper section having an inner bore, the position of the upper section being fixed relative to the wellbore, the distal end of the first work string having a whipstock, the whipstock having a whipstock exit and an inner bore providing a passage from the bore of the first work string to the whipstock exit; extending a drill tubing inside the first work string, the drill tubing having an inner bore leading to an opening at a distal end of the drill tubing; inserting at least a portion of the drill tubing through the whipstock; anchoring the first work string against an inner surface of the wellbore; introducing pressurized drilling fluid into the drill tubing and discharging the fluid through the opening of the drill tubing, the drilling fluid having abrasive material; directing the distal end of the drill tubing at the casing; cutting a hole in the casing using the discharged drilling fluid; extending the distal end of the drill tubing through the hole; and drilling an extended borehole from the hole using the pressurized drilling fluid. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Drawings are included for the purpose of illustrating certain aspects of the invention. Such drawings and the description thereof are intended to facilitate understanding and should not be considered limiting of the invention. Drawings are included, in which: 
         FIG. 1  is an elevation schematic view of a hydraulic drilling system according to an embodiment of the present invention. 
         FIG. 2  is an elevation schematic view the hydraulic drilling system according to another embodiment of the present invention. 
         FIG. 3  is a cross-section view of above surface equipment of the hydraulic drilling system shown in  FIG. 1  and  FIG. 2 . 
         FIG. 4 a    and  FIG. 4 b    are a cross-sectional view and an end view, respectively, of a positional device for measuring borehole position according to an embodiment of the present invention. 
         FIG. 5  is a schematic cut away view of the bottom hole assembly of the hydraulic drilling system shown in  FIGS. 1 and 2 , according to an embodiment of the present invention. 
         FIG. 6  is a schematic view of the bottom hole assembly of the hydraulic drilling system shown in  FIGS. 1 and 2 , according to another embodiment of the present invention. 
         FIG. 7  is a schematic view of the bottom hole assembly of the hydraulic drilling system shown in  FIGS. 1 and 2 , according to yet another embodiment of the present invention. 
         FIG. 8  is a schematic view of a seal assembly usable with the hydraulic drilling system shown in  FIGS. 1 and 2 , according to one embodiment of the present invention. 
         FIG. 9  is a schematic view of a deflection assembly usable with the hydraulic drilling system shown in  FIGS. 1 and 2 , according to one embodiment of the present invention. 
         FIG. 10  is a schematic view of an earth measurement system according to one embodiment of the present invention. 
         FIG. 11  is a schematic view of a steerable drill head usable with the hydraulic drilling system shown in  FIGS. 1 and 2 , according to one embodiment of the present invention. 
         FIGS. 12 a  and 12 b    are a plan view and end view, respectively, of sample borehole orientations in a horizontal well, according to one embodiment of the present invention. 
         FIGS. 13 a  and 13 b    are a plan view and end view, respectively, of sample borehole orientations in a horizontal well, according to another embodiment of the present invention. 
         FIGS. 14 a , 14 b , and 14 c    are a plan view, an elevation view, and an end view, respectively, of sample borehole orientations in a horizontal well, according to yet another embodiment of the present invention. 
         FIGS. 15 a  and 15 b    are a schematic elevation view and an end view of an earth measurement system according to one embodiment of the present invention. 
         FIGS. 16 a  and 16 b    are schematic views of an apparatus, in a standby position and a launch position, respectively, for placing an earth measurement device into the drill tubing according to an embodiment of the present invention. 
         FIG. 17  is a schematic view of an apparatus for placing an earth measurement device into the drill tubing according to another embodiment of the present invention. 
         FIG. 18  is a schematic cut away view of the bottom hole assembly according to another embodiment of the present invention. 
         FIGS. 19 a , 19 b , and 19 c    are schematic elevation views of a freeze fracture stimulation using a hydraulic drilling system and method in accordance with another embodiment of the present invention. 
         FIGS. 20 a  and 20 b    are schematic sequential views of a perforated casing resulting from the use of a hydraulic drilling method in accordance with one embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS 
     The detailed description set forth below in connection with the appended drawings is intended as a description of various embodiments of the present invention and is not intended to represent the only embodiments contemplated by the inventor. The detailed description includes specific details for the purpose of providing a comprehensive understanding of the present invention. However, it will be apparent to those skilled in the art that the present invention may be practiced without these specific details. 
     The system and method described herein allow the re-orientation of the whipstock (thus the re-direction of the drill head) without fully extracting the bottom hole assembly from the wellbore. The system and method are also configured to compensate for any axial work string movement due to fluctuations in fluid pressure during wellbore operations. These and other features of the present invention are described in detail herein below. 
       FIG. 1 ,  FIG. 3  and  FIG. 5  illustrate a hydraulic drilling system and method according to one embodiment of the present invention.  FIG. 1  shows a hydraulic drilling system  120  that is usable for drilling boreholes in an existing wellbore  2  formed within in a geological surface  1 . The existing wellbore  2  may be lined with casing  3 . In  FIG. 1 , the system  120  is illustrated in connection with the drilling of a lateral borehole  27 , which extends from the main wellbore  2  in the earth  5 . Main wellbore  2  can be vertical, deviated or horizontal and may be the wellbore extending from surface or a lateral therefrom. 
     The system  120  has components that are for use above surface and others that are for use below surface. In the illustrated embodiment shown in  FIG. 1 , the system includes for example an upper section  102 , which comprises a wellhead flange  4 , a wellhead control equipment  6 , a rotational device  7 , a rotating flange  8 , a hanger  15 , a sealing element  16 , and a movement control device  22 . In the illustrated embodiment, all of the upper section components are placed above surface  1 ; however, in other embodiments, one or more of the upper section components may be placed below surface  1 . 
     The wellhead control equipment  6  may be, for example, a blow out preventer. The rotational device  7  may be, for example, a tubing rotator. The hanger may be a flow tee having three openings all in fluid communication with one another. The sealing element  16  may be, for example, a pack-off head, a grease seal or a stripper packer. The movement control device  22  may be, for example, a winch, the rig draw works or an injector. The injector may be, for example, a coiled tubing or continuous rod injector. 
     In a sample embodiment, the components of the upper section  102  are connected one on top of another in the following sequence: wellhead flange  4 , wellhead control equipment  6 , rotational device  7 , rotating flange  8 , hanger  15 , and sealing element  16 , with the wellhead flange being the lowermost component (i.e. closest to the surface  1 ). Of course, the components of the upper section do not have to be connected in the exact order as described herein. Other configurations are possible. 
     Rotational device  7  is for rotating hanger  15  and seal assembly  16  through rotating flange  8 . In a sample embodiment, as illustrated in  FIG. 1 , rotational device  7  is connected to wellhead control equipment  6 , which is connected to wellbore flange  4 , which is above casing  3 . Rotating flange  8  has an upper flange and a lower flange that can rotate independently of one another. The upper end of rotational device  7  is connected to the lower flange of rotating flange  8 . Hanger  15  is connected to the upper flange of rotating flange  8 . 
     Each of the upper section components  4 ,  6 ,  7 ,  8 ,  15 , and  16  has an inner bore such that when the upper section is assembled, the inner bores substantially align to form an inner bore that extends from wellhead flange  4  to an upper surface of sealing element  16 . 
     Sealing element  16  includes an internal seal  28  and is attached to the upper surface of hanger  15 . Hanger  15  has an inlet  25  that is in fluid communication with the inner bore of the hanger  15 . Inlet  25  is connectable to a high pressure fluid source  24 , to allow high pressure fluid to enter the inner bore via inlet  25 . 
     Casing  3  has a proximate end and a distal end, with the proximate end being closer to the surface opening of wellbore  2 . In the illustrated embodiment, the proximate end of casing  3  extends above surface  1  and is connected to wellhead flange  4 . 
     In the illustrated embodiment shown in  FIG. 1 , the system includes a lower section  104 , which comprises a tubular work string  14 , connection string  21 , a flow-through device  20 , a drill tubing  19 , and a bottom hole assembly  9 . Bottom hole assembly  9  comprises a whipstock  10 , a seal assembly  11 , an anchor  12 , and an extendable and contractible tubular work string  13 . 
     The tubular work string  14  may comprise, for example, one or more of: casing, tubing, coiled tubing, and pipe. The connection string  21  may comprise, for example, one or more of cable, wireline, sucker rods, continuous rod, and coiled tubing. The anchor  12  may be, for example, a hydraulically activated anchor. The work string  13  may be, for example, an expansion joint. 
     Work string  14  has a proximate end, a distal end, and an inner bore extending therebetween. Work string  14  extends in the wellbore  2 , with its proximate end passing through the inner bores of wellhead control equipment  6 , rotational device  7 , rotating flange  8  and being attached to hanger  15 , by for example threaded connection. Work string  14  also engages the inner bore of rotational device  7 . In a sample embodiment, as shown in  FIG. 3 , work string  14  has a plurality of work string splines  32  on its outer surface and the inner bore of rotational device has a plurality of rotational device splines  31  for engaging work string splines  32 . Splines  31  and  32  are engageable with each other to transmit rotational movement from rotational device  7  to string  14 . In one embodiment, splines  32  are substantially parallel to the long axis of string  14  lengthwise, and extend radially outwardly from the outer surface of string  14 . Splines  31  extend radially inwardly from the inner surface of the rotational device towards the center of the inner bore thereof. Of course, other configurations of splines  31  and  32  are possible. 
     Rotational device  7  is held in place, through wellhead control equipment  6  and wellhead flange  4 , by casing  3  which is secured to the ground adjacent wellbore  2 . When rotational device  7  is activated, force is transmitted from rotational device splines  31  to work string splines  32 , thereby rotating work string  14  and imparting rotational forces on hanger  15 . Hanger  15  may rotate due to these rotational forces being transmitted though rotating flange  8 . When rotational device  7  is activated, work string  14  rotates relative to wellbore  2  and casing  3 . When rotational device  7  is inactivated, the engagement of rotational device splines  31  and work string splines  32  may prevent rotational movement of work string  14  during the placement of a borehole  27  using system  120 , which will be described in more detail hereinbelow. 
     The outer surface of work string  14  and the inner wall of casing  3  define an outer annulus  42 . In one embodiment, for example as illustrated in  FIGS. 1 and 3 , casing  3  includes an outlet  29  near its proximate end. The flow of fluid through outlet  29  is controlled by an outlet valve  30 . When valve  30  is open, outlet  29  allows fluid communication between annulus  42  and the space above surface  1  outside system  120 . When valve  30  is closed, fluid flow through outlet  29  is restricted. 
     The distal end of work string  14  is connected to extendable work string  13 , which in turn is connected to anchor  12 . Seal assembly  11  connects anchor  12  to whipstock  10 . Each of extendable work string  13 , anchor  12 , and seal assembly  11  has an inner bore such that when bottom hole assembly  9  is assembled, the inner bores are substantially aligned to form an inner bore that extends between the proximate end of extendable work string  13  and the distal end of seal assembly  11 . Whipstock  10  has an upper opening and a lower opening  17  (the latter also referred to as a “whipstock exit”), with a curved inner bore extending therebetween, to allow the movement of the drill tubing  19  therethrough. When rotational device  7  is activated, the rotation of string  14  causes whipstock  10  to rotate, which allows the radial direction of the whipstock exit to be changed. 
     Anchor  12  has a retracted position and an expanded position, the latter for engaging the inner surface of casing  3 . The effective outer diameter of anchor  12  is smaller in the retracted position than in the expanded position, such that anchor  12  can be run into the wellbore  2  in the retracted position without engaging the casing  3 . 
     In one embodiment, anchor  12  is activated from the retracted position to the expanded position by an increase in fluid pressure in its inner bore. For example, in the illustrated embodiment shown in  FIG. 5 , anchor  12  includes anchor pistons  40 , with the piston heads inside anchor  12 , in communication with the inner bore thereof, and the piston bodies being extendable radially outwardly beyond the outer surface of anchor  12  while the piston heads are maintained inside anchor  12 . Pistons  40  are positioned in anchor  12  such that when the fluid pressure inside anchor  12  increases, the increase in pressure pushes the piston heads radially outwardly inside anchor  12 , thereby extending the piston bodies radially outwardly beyond the outer surface of anchor  12  to increase the effective outer diameter of same, thus placing the anchor in the expanded position. The length of the piston bodies of pistons  40  are selected to be able to frictionally engage the inner wall of casing  3  when the pistons  40  are extended (i.e. when anchor  12  is in the expanded position). Of course, other anchoring mechanisms may be employed for system  120 . 
     Extendable work string  13  is extendable and contractible in the axial direction. As an example, extendable work string  13  may be an expansion joint. In a further example, extendable work string  13  may be made of two substantially concentric telescoping tubes: an outer tube having a larger diameter than the inner tube. The inner and outer tubes have a sealing surface within the annulus formed between the inner surface of the outer tube and the outer surface of the inner tube, thereby creating a sealed bore within the tubes for the passage of fluids therein. 
     Each tube is slideably movable in the axial direction relative to the other tube. In one embodiment, each tube has a first end and a second end, and when extendable work string  13  is in a minimum length position (i.e. when string  13  is in most contracted), the first end of the inner tube is near the first end of the outer tube. When string  13  is in a maximum length position (i.e. when string  13  is most expanded), the first end of the inner tube is near the second end of the outer tube. In a further embodiment, the first end of the outer tube is threaded and the second end of the inner tube is threaded. In an alternative embodiment, the second end of the outer tube is threaded and the first end of the inner tube is threaded. The threading of the tubes allows the extendable work string to be threadedly connected to the distal end, within or at the proximate end of working string  14  and anchor  12 . The sealing surface between the tubes is configured such that it is maintained when the string  13  is minimum and maximum length positions, and anywhere in between. 
     String  13  may be configured such that it is free to extend and contract in the axial direction of work string  14 . Preferably, work string  13  is connected to work string  14  such that their central long axes are substantially parallel or align with one another. For example, work string  13  may be integrated with work string  14  to form a length thereof. Alternatively, string  13  may have friction and/or spring type devices to restrict or counteract axial movement thereof. In a preferred embodiment, the work string  13  is positioned near the whipstock. 
     The drill tubing  19  has a proximate end and a distal end. The distal end includes a drill head  18 . The drill tubing  19 , drill head  18 , and the flow through device  20  (if included), collectively, are referred to herein as the drill assembly. In one embodiment, drill head  18  is capable of rotation and handling abrasives. An inner bore passes through the drill tubing and is open at the drill head  18 . The drill head can be of any suitable design, and in one embodiment, it includes a nozzle that opens from its inner bore to its outer surface and acts to produce a cutting jet from drilling fluid passing therethrough that is capable of breaking down formation materials. In addition to producing the cutting jet, the drilling fluid exerts a force on the drill head  18  which drives the drill tubing  19  and the drill head  18  in the forward direction to form borehole  27 . 
     Drill tubing  19  is extended inside work string  14  and is movable axially within the work string. For use to drill a borehole  27 , drill tubing  19  is inserted through the inner bores of work string  14 , extendable work string  13 , anchor  12 , seal assembly  11 , and whipstock  10 , with the distal end of drill tubing  19  extending into the inner bore of whipstock  10 . The curvature of the whipstock inner bore acts to bend drill tubing  19  advancing through the whipstock and to direct the tubing outwardly from the long axis of the work string  14 . In one embodiment, as shown for example in  FIG. 5 , rollers may be provided in the inner bore of whipstock  10  to aid the passage of the drill tubing  19  therethrough. By advancement of the drill tubing  19  through the whipstock  10 , the distal end of the drill tubing may be directed away from the main wellbore  2  to form lateral borehole  27 . A seal  41  is provided in seal assembly  11  to control and/or substantially prevent fluid flow through the interface between the drill tubing and the whipstock inner bore. 
     The connection string  21  extends inside work string  14 , and has a proximate end and a distal end. The flow-through device  20  connects the distal end of connection string  21  to the proximate end of the drill tubing  19 , inside the work string  14 . The connection string  21  passes through the inner bores of the upper section components. The proximate end of connection string  21  extends beyond the upper surface of the sealing element  16  and connects to the movement control device  22 . 
     The flow-through device  20  includes at least one conduit  26  opening at a first end on the outer surface of the flow-through device and extending to open at a second end into the inner bore of drill tubing  19 . Conduit  26  allows fluid communication between the outer surface of flow-through device  20  and the inner bore of drill tubing  19  through to drill head  18 . 
     Flow-through device  20  and drill tubing  19  are moveable axially inside the work string by movement of the connection string  21 . Drill tubing  19  and connection string  21  may comprise one or more of the following: cable, wireline, a string of rods, such as sucker rods (including standard form sucker rods, polish rods, etc.), continuous rod, continuous coiled tubing, etc. The term “continuous” herein refers to a length of connection string that is unbroken along its length that is passed down the main wellbore  2 , as opposed to a connection string formed of a plurality of rods connected end to end. Connection string  21  is advanced axially into the work string by movement control device  22 . Movement control device  22  applies tensile forces and/or compressive forces to connection string  21  to help control axial advancement and/or retraction of connection string  21 , flow through device  20 , drill tubing  19  and drill head  18 . Movement control device  22  may be for example, a winch, the rig draw works, or an injector. 
     Sealing element  16  in the upper section provides a seal between the work string  14  and the connection string  21  such that a sealed inner annulus  23  is formed between the outer surface of the connection string/flow-through device/drill tubing and the inner surface of the work string  14 . As noted hereinbefore, inner annulus  23  is sealed at its lower end by seal assembly  11 . Seal assembly  11  is configured to seal against the outer diameter of drill tubing  19  to maintain fluid pressure containment in the annulus  23  while allowing the tubing  19  to move forward through the seal  41 . 
     A method according to one aspect of the present invention includes: running a work string  14  into an existing vertical, deviated or horizontal wellbore  2 . A bottom hole assembly  9  is provided at the distal end of the work string  14 . The bottom hole assembly  9  includes a whipstock that directs the drill head  18  of system  120 , for example in a radial direction from the long axis of the existing wellbore  2 . 
     More specifically, the method comprises lowering the distal end of work string  14  into wellbore  2  through the inner bores of rotating flange  8 , rotational device  7  and wellhead control system  6 . The method further comprises connecting the proximate end of the drill tubing  19  to the distal end of the connection string  21  using the flow-through device  20 , and then lowering the drill tubing, the flow-through device, and the connection string through the inner bore of hanger  15  and then into work string  14 . The proximate end of the work string  14  is connected to hanger  15 . 
     The drill tubing  19 , along with the drill head  18  attached to the distal end of thereof, and flow-through device  20  attached to the proximate end of the drill tubing  19  are run into wellbore  2  axially by extending the length of the connection string  21  inside the work string  14  using the movement control device  22 . As more length of the connection string  21  is extended into the work string, the more the drill tubing advances into the wellbore  2 . The connection string  21  is advanced axially inside the work string by movement control device  22  until drill head  18  reaches seal assembly  11  and is sealingly engaged therewith. 
     Once the drill head  18  enters the sealing assembly  11 , sealing element  16  is incorporated above surface such that seal  28  sealingly engages the outer surface of the connection string to fluidly seal the space above the sealing element from the space below. Inlet  25  of hanger  15  is connected to a high pressure fluid source  24 . High pressure fluid is then injected into inner annulus  23 , via inlet  25 . This high pressure fluid is pumped down annulus  23  and enters the drill tubing  19  via conduit  26  of flow-through device  20 . 
     Once inside the drill tubing  19 , the fluid flows to the drill head  18  whereby the fluid pressure generates a downward force on the drill tubing. The fluid also exits the drill head  18  as a high-pressure cutting jet which is directed at the formation that is to be cut away to create a lateral bore  27 . Depending on where borehole  27  is to be drilled into earth  5 , casing  3  may or may not cover the part of the inner wall of wellbore  2  where borehole  27  is to be drilled. If casing  3  covers the part of the inner wellbore wall where borehole  27  is to be drilled, casing  3  is removed, milled or perforated prior to the placement of borehole  27 . A method for perforating casing is described hereinbelow. 
     The increase in fluid pressure in annulus  23  activates anchor  12  to the expanded position, thereby keeping bottom hole assembly  9  in place during drilling operations. Any axial movement in work string  14  caused by pressure fluctuations can be compensated for by extendable work string  13 . The fluid cutting jet formed at drill head  18  penetrates earth  5  to create borehole  27 . The hydraulic forces created inside drill head  18  drives the drill tubing  19  forward and movement control device  22  controls the forward movement of the drill tubing  19  via the connection string  21 . In one embodiment, outlet valve  30  is opened to allow fluid returning from borehole  27  to flow up the wellbore through outer annulus  42  and exit at outlet  29  to surface facilities (not shown). 
     When the drilling of borehole  27  is completed, the drill tubing is retracted through the upward movement of the connection string until the drill head  18  is retracted through the whipstock to above seal assembly  11 . If desired, whipstock  10  can be re-oriented by rotating work string  14 , via the rotation of hanger  15  using rotational device  7 . Once whipstock  10  is re-oriented, drill head  18  may once again be lowered and engaged in seal assembly  11  and another borehole (not shown) may be drilled. This process may be repeated as many times as desired. 
     In a further embodiment, system  120  may be used for downhole fracture stimulation. As mentioned above, during drilling operations, at least some of the drilling fluid exiting drill head  18  flows upwards in outer annulus  42  towards surface, and may be collected through valve  30 . However, keeping valve  30  closed or pressure-controlled causes the pressure in outer annulus  42  to increase, thereby increasing the fluid pressure in borehole  27 . When the fluid pressure in borehole  27  increases to exceed the fracture pressure of the earth  5  in borehole  27 , the earth fractures and a fracture is generated at the borehole. The pressure in annulus  42  may be modulated by controlling the opening and closing of valve  30  as drill head  18  extends into borehole  27 , thus it may be possible to initiate fractures in multiple locations along borehole  27 . Therefore, the system allows the initiation of fractures at one or more desired locations, at a distance from the wellbore. 
     In another embodiment, a portion of outer annulus  42  may be fluid sealed by placing a packer system (not shown) comprising at least one packer in annulus  42 , and engaging the packer system when desired, to stop the flow of fluid back to the surface. Once the packer system is engaged to prevent fluid in annulus  42  to exit at surface, the pressure in annulus  42  below the packer system increases, thereby increasing the fluid pressure in borehole  27 . When the fluid pressure in borehole  27  increases to exceed the fracture pressure of the earth  5  in borehole  27 , the earth fractures and a fracture is generated at the borehole. 
     In one embodiment, the packer system in communication with the fluid pressure inside work string  14  such that the packer system is engaged when the pressure within work string  14  exceeds an engagement threshold pressure and is disengaged when the pressure within work string  14  is below a disengagement threshold pressure, which may or may not be the same as the engagement pressure. The packer system may be installed in work string  14 . In an alternative or additional embodiment, the packer system may be engaged and/or disengaged by the exertion of axial forces on work string  14  from surface. The axial forces are opposed by anchor  12  thus resulting in the engagement and/or disengagement of the packer system. Whether modulating the pressure within string  14  and/or applying axial forces on string  14 , the packer system may be engaged and disengaged more than once during the placement of borehole  27 , thereby allowing the initiation of fractures in multiple locations along borehole  27 . 
     In yet another embodiment, a packer system (not shown) is placed directly into the borehole as part of the drill tubing  19 , above drill head  18 . When the borehole is drilled to a prescribed length, the packer system is engaged while the flow of drilling fluid continues. Once the packer system is engaged, the pressure in the borehole increases from the drilling fluid buildup. When the fluid pressure in borehole  27  increases to exceed the fracture pressure of the earth  5  in borehole  27 , the earth fractures and a fracture is generated at the borehole. This process may take place one or more times during the placement of borehole  27 . 
     In one embodiment, the packer system in communication with the fluid pressure inside drill tubing  19  such that the packer system is engaged when the pressure within drill tubing  19  exceeds an engagement threshold pressure and is disengaged when the pressure within drill tubing  19  is below a disengagement threshold pressure, which may or may not be the same as the engagement pressure. By modulating the pressure within tubing  19 , the packer system may be engaged and disengaged more than once during the placement of borehole  27 , thereby allowing the initiation of fractures in multiple locations along borehole  27 . 
     In a further embodiment, as illustrated in  FIG. 18 , a passage  205  may be provided in the down hole assembly to allow some fluid from annulus  23  to bypass lower seal assembly  11 . Allowing some fluid to bypass the seal assembly  11  may be helpful in providing additional circulation fluids and/or a cooling source for electronics in elevated temperature wells. Preferably, the effective inner diameter of the passage  205  is selected to allow fluid flow therethrough without substantially reducing the fluid pressure inside annulus  23 . 
     A method for heating or cooling the earth near the borehole comprises positioning the drill head at or near the distal end of the borehole; supplying a fluid into the drill tubing and discharging the fluid through the opening at the distal end of the drill tubing, the fluid having a temperature different from an initial temperature of earth surrounding the distal end of the borehole, thereby changing the initial temperature to a new temperature; and ceasing the supply of the fluid in the drill tubing to allow the earth to return to the initial temperature. The method may further comprise changing the initial temperature to the new temperature causes a phase change of at least one liquid in the earth near the distal end of the borehole. Still further, the method may comprise generating or augmenting fractures in the surrounding earth by supplying a pressurized fluid into the drill tubing and injecting the pressurized fluid into the borehole through the opening of the drill tubing. The fluids that may be used with the method include for example: liquid or gaseous carbon dioxide, liquid or gaseous nitrogen, steam. 
     The method may further comprise injecting a flow manipulation fluid through the drill tubing and into the borehole via the opening of the drill tubing. The flow manipulation fluid may include for example one or more of: steam, carbon dioxide, nitrogen, surfactant, lubricant, solvent, retardant, resin, polymer, gel, and cement. 
     In another embodiment, the borehole&#39;s surrounding earth may be heated by an earth manipulation device that can be selectively activated to generate heat, which may include for example, a resistive heating element, a microwave generating device, an antenna, etc. For example, the resistive heating element may be installed on the drill tubing or may be integrated with the drill tubing itself. 
     For example, a method for freeze fracture stimulation can be performed for borehole  27 . With reference to  FIGS. 19 a  to 19 c   , the method comprises injecting a cooling fluid into the borehole  27  to cool the borehole and the nearby earth  190 . The cooling fluid may be for example: (i) a gas, such as carbon dioxide or nitrogen; or (ii) a liquid that becomes a gas under reservoir conditions, such as liquid carbon dioxide or liquid nitrogen. The cooling fluid is injected into drill tubing  19  and exits drill head  18 , while inside borehole  27 . When it exits the drill head, the cooling fluid expands into a gas and the resulting Joule-Thompson effect causes the cooling of any existing fluid in the borehole and the surrounding earth  190 . 
     Referring to  FIG. 19 b   , if the surrounding earth  190  contains water, the temperature of the water may be reduced below its freezing temperature and becomes ice  192  as a result of the cooling effect. Since ice has a higher volume than liquid water, the ice  192  creates stresses within the earth  190 . If these stresses are above the fracture stresses of the earth, then fracture stimulation occurs in the borehole. 
     Referring to  FIG. 19 c   , when the flow of cooling fluid into the borehole ceases, the temperature in the borehole rises and ice  192  melts, which then causes fractured material  194  from earth  190  to fall to a lower inner surface of the borehole. The fracture material  194  may be cleaned out by circulating drilling fluid through drill head  18  and into the borehole, so that fracture material  194  can flow up outer annulus  42  with the drilling fluid. 
     The above described method may further comprise injecting a flow manipulation fluid through the drill tubing and into the borehole via the opening of the drill tubing. The flow manipulation fluid may include for example one or more of: steam, carbon dioxide, nitrogen, surfactant, lubricant, solvent, retardant, resin, polymer, gel, and cement. 
     The method may further comprise injecting a flow manipulation fluid through the drill tubing and into the borehole via the opening of the drill tubing to manipulate the permeability of the earth, and the flow manipulation fluid is one or more of: a retardant, resin, polymer, gel, and cement. 
     The borehole may be near a reservoir containing a reservoir fluid with a viscosity, and the method may further comprise injecting a flow manipulation fluid through the drill tubing and into the borehole via the opening of the drill tubing to manipulate the viscosity of the reservoir fluid, and the flow manipulation fluid is one or more of: steam, carbon dioxide, nitrogen, lubricant and solvent. 
     The method may further comprise injecting a surfactant through the drill tubing and into the borehole via the opening of the drill tubing to manipulate the rock wettability of the earth. 
     In another embodiment, the borehole&#39;s surrounding earth may be heated by an earth manipulation device that can be selectively activated to generate heat, which may include for example, a resistive heating element, a microwave generating device, an antenna, etc. For example, the resistive heating element may be installed on the drill tubing or may be integrated with the drill tubing itself. 
       FIG. 2 ,  FIG. 3  and  FIG. 5  illustrate another embodiment of the hydraulic drilling system and method of the present invention. In this embodiment, the components of the system  220  are the same as those shown in the embodiment illustrated in  FIG. 1 , except that the connection string and flow through device are omitted. In this embodiment, a drill tubing  19 ′ is used. Drill tubing  19 ′ has a proximate end and a distal end. In one embodiment, the proximate end of the drill tubing  19 ′ is above the ground surface of the wellbore opening and a portion of the tubing  19 ′ is contained on a spool at surface. As tubing  19 ′ is advanced into the wellbore, the tubing is unrolled from the spool. 
     The proximate end is fluidly connectable to high pressure fluid source  24 . The distal end includes a drill head  18 . Drill tubing  19 ′ is extendable through movement control device  22 , through the inner bores of all the components of the upper section  102 , down work string  14 , and through the bottom hole assembly  9 . When drill tubing  19 ′ is extended inside work string  14 , an inner annulus  23 ′ is formed between the outer surface of the drill tubing  19 ′ and the inner surface of work string  14 . 
     A method for drilling a borehole  27  in wellbore  2  using system  220  comprises lowering the distal end of work string  14 , with bottom hole assembly  9  attached, into wellbore  2  through the inner bores of rotating flange  8 , rotational device  7  and wellhead control system  6  and connecting the proximate end of work string  14  to hanger  15  which is then attached to the top of rotating flange  8 . The method further comprises connecting the proximate end of the drill tubing  19 ′ to the high pressure fluid source  24 , and then placing the drill tubing  19 ′ through the movement control device  22  such that movement control device engages a portion of the drill tubing  19 ′. Further, the method comprises lowering the drill tubing  19 ′ through the inner bores of sealing element  16  and hanger  15 , and then into work string  14 . Sealing element  16  is then incorporated that seal  28  sealingly engages the outer surface of drill tubing  19 ′ to fluidly seal the space above the sealing element from the space below. 
     The drill tubing  19 ′, along with the drill head  18  attached to the distal end of thereof, is advanced axially into wellbore  2  using the movement control device  22 . The drill tubing  19 ′ is advanced axially inside the work string by movement control device  22  until drill head  18  reaches seal assembly  11  and is sealingly engaged therewith. 
     High pressure fluid is then injected into drill tubing  19 ′ from the high pressure fluid source. Once inside the drill tubing  19 ′, the fluid flows to the drill head  18  whereby the fluid pressure generates a downward force on the drill tubing. The fluid also exits the drill head  18  as a high-pressure cutting jet which is directed at the formation that is to be cut away to create a lateral bore  27 . 
     Optionally, high pressure fluid may be injected into inner annulus  23  via inlet  25  to activate anchor  12  in order to hold bottom hole assembly  9  in place during operations. 
     Any axial movement in work string  14  caused by pressure fluctuations can be compensated for by extendable work string  13 . The fluid cutting jet formed at drill head  18  penetrates earth  5  to create borehole  27 . The hydraulic forces created inside drill head  18  drives the drill tubing  19 ′ forward and movement control device  22  controls the forward movement of the drill tubing  19 ′. In one embodiment, outlet valve  30  is opened to allow fluid returning from borehole  27  to flow up the wellbore through outer annulus  42  and exit at outlet  29  to surface facilities (not shown). 
     When the drilling of borehole  27  is completed, the drill tubing  19 ′ is retracted through by the movement control device  22  until the drill head  18  is retracted through the whipstock to above seal assembly  11 . If desired, whipstock  10  can be re-oriented by rotating work string  14 , via the rotation of hanger  15  using rotational device  7 . Once whipstock  10  is re-oriented, drill head  18  may once again be lowered and engaged in seal assembly  11  and another borehole (not shown) may be drilled. This process may be repeated as many times as desired. 
     In one embodiment, system  220  may be used for fracture stimulation and freeze fracture stimulation in the same ways as described above with respect to system  120 . 
       FIG. 6  illustrates a sample bottom hole assembly that is usable with the above described systems. More specifically, the bottom hole assembly shown in  FIG. 6  can be used for circumferentially aligning same.  FIG. 6  only shows the components of the bottom hole assembly below anchor  12 . In the illustrated embodiment, bottom hole assembly  9  includes centralizers  60  on its outer surface to keep the outer surface of the whipstock from coming into contact with the inner wall of the wellbore or casing. Preferably, the centralizers  60  are installed axially above and below the whipstock. Further, whipstock  10  is mounted between two swivels  61 . Preferably, each end of the swivel  61  can rotate independently of the other end. The swivels  61  give whipstock  10  the freedom to rotate about the central long axis of the bottom hole assembly relative to the other components of the assembly. 
     In one embodiment, a weight  62  is placed on whipstock  10  for aligning the whipstock exit  17  to a desired exit direction. Weight  62  increases the mass of whipstock  10  in an eccentric manner causing the whipstock exit to be biased in a particular direction by the force of gravity, as the weight  62  tends to lie on the bottom (as determined by gravity). In the illustrated embodiment in  FIG. 6 , weight  62  is disposed on the side of the whipstock that is substantially directly opposite to the whipstock exit, to direct the whipstock exit in a substantially vertical direction (as determined by gravity) when the bottom hole assembly is in a substantially horizontal wellbore. By placing weight  62  on different parts of the whipstock, various orientations of the whipstock exit direction may be achieved. 
     In a further embodiment, the bottom hole assembly includes a drive mechanism  63  for rotating whipstock  10  between swivels  61  about the central long axis of the bottom hole assembly. Drive mechanism  63  may be for example an electric motor, which may be for example powered by batteries or another electrical power storage device (not shown) or stored mechanical energy powered by spring energy (not shown). 
     In one embodiment, it may be possible to recharge either power source for the drive mechanism from energy derived from the hydraulic energy of fluid flowing through work string  14 . Hydraulic energy can be derived from fluid flow, for example, by using a water wheel or a turbine and this hydraulic energy can be changed to a number of different forms of energy including electrical and mechanical energy. In one embodiment, with reference to  FIGS. 1, 2 and 6 , when nozzle  18  is above seal assembly  11 , fluid flow is directed across a rotating device (not shown), which may be a turbine or a water wheel, that is connected to a generator (not shown) which in turn is connected to the drive mechanism  63 . The rotation of the rotating device caused by fluid flow thereacross turns the generator, thereby electrically charging the drive mechanism  63 . 
     In a further embodiment, when nozzle  18  is above seal assembly  11 , fluid flow is directed across a rotating device (not shown) which is connected through a gearing mechanism (not shown) to springs (not shown) that drive the stored mechanical energy. The rotation of the rotating device caused by fluid flow thereacross turns the gearing mechanism, thereby exerting a force on the springs which can be selectively released subsequently as stored mechanical energy. 
     In a still further embodiment, when nozzle  18  is above seal assembly  11 , fluid flow is directed through an electrical coil (not shown) which is connected to the drive mechanism  63 . If the fluid or particles in the fluid flow have electrical or magnetic qualities, an electric current is generated by the electrical coil, thereby electrically charging drive mechanism  63 . 
     Bottom hole assembly  9  may include one or both of weight  62  and drive mechanism  63 . 
     If a drive mechanism is used for bottom hole assembly  9 , the drive mechanism may be controlled from surface using radio signals, mud pulse signals, pressure signals, acoustical signals, or a combination thereof. In a further embodiment, the drive mechanism may be controlled by a preprogrammed down hole processor. 
       FIG. 7  shows a sample bottom hole assembly that is usable with the above described systems. More specifically, the bottom hole assembly shown in  FIG. 7  can be used to axially align same.  FIG. 7  only shows the components of the bottom hole assembly below anchor  12 . In the illustrated embodiment shown in  FIG. 7 , the bottom hole assembly has energy transfer devices installed on its outer surface. The energy transfer devices may be, for example, wheels  70 , treads  71 , inchworm mechanisms (not shown), or a combination thereof. 
     In one embodiment, the energy transfer devices are spring loaded and aligned axially and circumferentially so that they constantly push against the inner wall of wellbore  2  or casing  3  to keep the whipstock from contacting the inner wall of the wellbore or casing. The energy transfer devices may be used with swivels  61  ( FIG. 6 ) and may be configured such that the whipstock can be rotated about its central long axis by use of swivels  61  without moving the energy transfer devices. More specifically, the energy transfer devices may be situated closer to the wellbore opening at surface than an upper swivel and further from the wellbore opening than a lower swivel, such that the swivels are positioned between the energy transfer devices. 
     In one embodiment, the bottom hole assembly includes a drive mechanism  72  to supply power to wheels  70  or treads  71  to drive the movement of wheels  70  or treads  71 . The movement of wheels  70  or treads  71  in turn causes the whipstock to move in the direction of its long central axis, thereby allowing the relocation of the whipstock axially in casing  3  or wellbore  2 . If extendible and contractible work string  13  is also included, it is then possible to move bottom hole assembly  9  axially relative to the wellbore without adjusting work string  14  at surface. Drive mechanism  72  may be for example an electric motor, which may be for example powered by batteries or another electrical power storage device (not shown) or stored mechanical energy powered by spring energy (not shown). Drive mechanism  72  may be recharged and/or controlled in ways as described with respect to drive mechanism  63 . 
       FIG. 8  illustrates a sample seal assembly configuration usable with the above described systems. Seal assembly  11  includes a seal  80 , which may be replaced at surface without having to retract the work string  14  from the wellbore. Seal assembly  11  has an inner bore for receiving seal  80 . Seal  80  has an outer surface and an inner axial bore, the latter providing a passage for drill tubing  19 . 
     In this embodiment, the drill head  18  of drill tubing  19  has an outer diameter that is greater than the diameter of the inner bore of seal  80 . Further, the outer surface of seal  80  and the inner bore of seal assembly  11  are shaped such that they mate with and frictionally engage each other, and seal  80  is prevented from moving all the way through the inner bore past the lower end of the seal assembly  11 , when seal  80  is received inside seal assembly  11 . For example, as shown in the illustrated embodiment, the inner bore of seal assembly  11  and the outer surface of seal  80  are both generally frustoconically shaped, i.e. the effective outer diameter gradually reduces from an upper end to a lower end. Since the outer diameter of the upper end of seal  80  is greater than that of the lower end of seal assembly  11 , the inner bore of seal assembly  11  forms a seat for receiving seal  80 , and seal  80  is prevented from going through the seal assembly. Preferably, seal  80  can only be removed from seal assembly  11  by an upward force without substantial deformation of the seal. 
     To set up the seal assembly for drilling operations, seal  80  is placed on the drill tubing, with the drill tubing slidably movable in the inner bore of the seal  80 , and the drill head  18  is connected to the distal end of the drill tubing, below seal  80 . The drill tubing, along with seal  80  and drill head  18 , is run into the wellbore inside work string  14 . When seal  80  reaches seal assembly  11 , seal  80  is received in the seat of seal assembly  11  and frictionally engages same while the drill tubing continues to advance down the work string. The engagement between seal assembly  11  and seal  80  forms a fluid seal to prevent substantially all fluid flow through seal assembly  11 , except via the inside of drill tubing  19 . 
     To replace seal  80 , the drill tubing  19  is pulled upwards inside the work string and sealingly passes through seal  80 . When drill head  18  reaches and abuts against seal  80 , drill head  18  is prevented from passing through seal  80  since the outer diameter of drill head  18  is larger than the diameter of the inner bore of the seal  80 . As the drill tubing  19  continues to retract from the work string, the drill head  18  exerts an upward force on the lower face of seal  80 , until the force is sufficient to disengage and unseat seal  80  from seal assembly  11 . The unseated seal  80  then moves upwards with the drill tubing to surface where the seal  80  can be replaced. At surface, the drill head  18  and seal  80  are removed from the drill tubing. Then, a replacement seal is installed on the drill tubing and the drill head  18  is reinstalled at the distal end of the drill tubing below the replacement seal. Once the seal is replaced and the drill head is reattached, the drill tubing can be lowered back into wellbore  2  and the replacement seal can engage the sealing assembly as described above. 
       FIG. 9  illustrates a sample whipstock deflection assembly usable with the above described systems. The whipstock includes a whipstock deflection assembly  91  that is replaceable at surface without having to retract the work string from the wellbore. In this embodiment, whipstock  10  has an inner bore for receiving deflection assembly  91 . The inner bore is in communication with a passage  210  that leads to a lower opening on the outer surface of a side of whipstock  10 . Deflection assembly  91  has an outer surface and an inner curved bore, the latter providing a passage for drill tubing  19 . 
     The drill head  18  of drill tubing  19  has an outer diameter that is a greater than the diameter of the inner bore of deflection assembly  91 . Further, the outer surface of deflection assembly  91  and the inner bore of whipstock  10  are shaped such that they mate with and frictionally engage each other, and the inner bore of deflection assembly  91  is in communication with passage  210 , when seal deflection assembly  91  is received inside whipstock  10 . 
     For example, as shown in the illustrated embodiment, the inner bore of whipstock  10  and the outer surface of deflection assembly  91  are both generally frustoconically shaped, i.e. the effective outer diameter gradually reduces from an upper end to a lower end. The inner bore of whipstock  10  forms a seat for receiving and mating with deflection assembly  91  and when deflection assembly  91  is seated in whipstock  10 , its inner bore is substantially aligned with passage  210  to allow for the continuous passage of the drill tubing from the deflection assembly  91  through the passage  210  to the outer surface of whipstock  10 . 
     In a further embodiment, a recess is formed at the lower opening of the inner bore of deflection assembly  91 . A shoulder is provided at the lower opening in the recess of deflection assembly  91 . 
     Seal assembly  11  has an inner bore that is configured to receive and frictionally engage a seal  90 . Seal  90  has an inner bore for the passage of drill tubing  19  therethrough. When seal  90  is engaged with seal assembly  11 , with drill tubing  19  through the inner bore of seal  90 , substantially no fluid can flow from one side to the other side of the seal assembly except through the drill tubing. In one embodiment, seal assembly  11  and seal  90  are shaped and configured as described above with respect to seal assembly  11  and  80 , respectively, in  FIG. 8 . The diameter of the inner bore of seal assembly  11  is sized throughout the length of the inner bore such that at least a portion of the deflection assembly  91  can extend past the lower face of the seal assembly and be received in whipstock  10 . 
     To set up the seal assembly for drilling operations, deflection assembly  91  is placed on the drill tubing and seal  90  is placed on the drill tubing above the deflection assembly  91 , with the drill tubing slidably movable through the inner bores of the seal and the deflection assembly. The drill head  18  is connected to the distal end of the drill tubing, below deflection assembly. The drill head  18  is receivable in the recess at the lower opening of deflection assembly  91 . 
     The drill tubing, along with seal  90 , deflection assembly  91 , and drill head  18 , is run into the wellbore inside work string  14 . When deflection assembly  91  reaches whipstock  10 , deflection assembly  91  is received in the seat of whipstock  10  and frictionally engages same while the drill tubing continues to advance down the work string. When the deflection assembly  91  is received in whipstock  10 , seal  90  is also received in and frictionally engages seal assembly  11 . The engagement between seal assembly  11  and seal  90  forms a fluid seal to prevent substantially all fluid flow through seal assembly  11 , except via the inside of drill tubing  19 . Further, when the deflection assembly  91  is received in whipstock  10 , the lower opening of deflection assembly  91  is substantially aligned with passage  210  of whipstock  10 , to allow drill head  18  and drill tubing  19  to continue advancing downhole through whipstock  10 . 
     To replace deflection assembly  91  and/or seal  90 , the drill tubing  19  is pulled upwards inside the work string and sealingly passes through seal  90 . When drill head  18  reaches the recess and abuts against the shoulder in deflection assembly  91 , drill head  18  is prevented from passing through the inner bore of the deflection assembly because the outer diameter of drill head  18  is larger than the diameter of the inner bore of the deflection assembly. As the drill tubing  19  continues to retract from the work string, the drill head  18  exerts an upward force on the shoulder of the deflection assembly, until the force is sufficient to disengage and unseat the deflection assembly from the whipstock, and also the seal  90  from the seal assembly. The unseated deflection assembly  91  and seal  90  then move upwards with the drill tubing to surface where deflection assembly  91  and/or seal  90  can be replaced. 
     At surface, the drill head  18  and deflection assembly  91  and/or seal  90  are removed from the drill tubing. Then, a replacement deflection assembly and/or seal is installed on the drill tubing and the drill head  18  is reinstalled at the distal end of the drill tubing below the deflection assembly. Once the deflection assembly  91  and/or seal  90  is replaced and the drill head is reattached, the drill tubing can be lowered back into wellbore  2  and the deflection assembly and seal  90  can engage the whipstock and the sealing assembly, respectively, as described above. 
       FIG. 10  shows a sample earth measurement system that may be used with the above described systems and methods. Sensors (or signal receivers) or other earth measurement devices  100  are installed on the bottom hole assembly  9  or whipstock  10  at various specific locations (i.e. the sensors&#39; location in relation to other components such as the whipstock, the drill head, etc. is known.). The earth measurement system allows various measurements to be taken at one or more distant locations away from the wellbore. 
     In one embodiment, sensors  100  are acoustic sensors. As borehole  27  is drilled, drill head  18  is extended into borehole  27  such that there is a distance between drill head  18  and whipstock  10 . The sound generated by high pressure fluid exiting drill head  18  is received by sensors  100 . Acoustic signals generated by sensors  100  may then be processed to triangulate the location of drill head  18 . Furthermore, such signals may be processed to determine qualities and parameters of the earth between nozzle  18  and sensors  100 . Preferably, two or more sensors are used to determine the location of the drill head two-dimensionally. More preferably, three or more sensors are used perform three-dimensional triangulation. 
     Alternatively or additionally, a signal source (or signal emitter)  101  is placed on drill head  18  or on tubing  19  near drill head  18 . Signal source  101  may be for example a sonic, electrical, magnetic, or radioactive signal source. In an alternative embodiment, the signal source  101  is located on the bottom hole assembly and the sensors  100  are located on or near drill head  18 . Sensors  100  are sensors that are capable of sensing the strength and/or existence of the signal emitted by the signal source  101 . For example, possible data that can be sensed and collected by sensor  100  may include, for example, sound waves, spontaneous potential, resistivity, neutron density, bulk density, magnetic flux, gamma rays, x-rays, etc. The collection of other measurements is also possible. 
     The signal transmitted between source  101  and sensor  100  may be used to analyze the physical properties of the earth between source  101  and sensor  100 . The physical earth properties that may be determined by the signal transmitted between source  101  and sensor  100  include for example, structure, stress, lithology, porosity, permeability and saturations of water, oil, and gas, etc. 
     For example, a sonic signal generated by source  101  and sensed by sensor  100  may be used to determine the porosity of the earth between source  101  and sensor  100  using the same principles used by sonic wireline tools. More specifically, sound travels faster through a solid than in a gas or liquid so sound travels through the rock matrix faster than through the pore space (porosity). As such, the time it takes for sound to travel from the source to the sensor varies depending on the porosity of the rock matrix of the surrounding earth. It is therefore possible to calculate the porosity of the rock matrix by determining the speed of sound through the rock matrix. For other measurements, which may include for example spontaneous potential, resistivity, neutron density, bulk density, magnetic flux, and gamma rays, other principles apply. 
     The measurements determined using the above-described earth measurement system and method may produce different results from wireline tools since the signal passes directly through the rock, whereas with wireline tools the signal passes tangentially through the rock. Therefore, the above-described earth measurement system and method may provide rock properties measurements that are not obtainable from existing wireline technology. For example, x-rays require straight line transmission through the rock matrix so it is not possible for wireline tools that are restricted to a lineal wellbore to use x-rays to determine rock properties. 
     The measurements taken by an earth measurement device may be stored locally in a recording device (not shown) downhole and/or a recording device positioned remotely at surface outside the wellbore. Measurements may be transmitted to the recording device via radio signals, acoustical signals, and/or a wire. The measurements collected may then be used by an electromagnetic, pressure or acoustical data transmission system. The measurements collected may also be used to generate data on resistivity, water saturation, spontaneous potential porosity, permeability, neutron density, and/or bulk density. 
       FIGS. 4 a  and 4 b    illustrate a positional measurement device  113  to measure the orientation and location of borehole  27 , the distal end of drill tubing  19 , and/or whipstock exit  17 . In one embodiment, positional device  113  comprises a positional device casing  119 , positional measurement components  116 , and optionally a power source  117 . Components  116  and power source  117  are housed in casing  119 , which is designed to withstand operating conditions, such as forces, temperatures and pressures, before, during and after the placement of borehole  27  ( FIGS. 1 and 2 ). 
     Positional measurement components  116  may be, for example, one or more of gyroscopes, accelerometers, magnetometers, and micro-electronic machines (MEMs). Power source  117 , if included in device  113 , may be for example batteries. In the illustrated embodiment, positional device components  116  are at or near the proximate end of drill head  118  and power source  117  is at or near the distal end of drill head  118 ; however, in other embodiments, components  116  and power source  117  may be disposed at different positions relative to drill head  118  or drill tubing  19 . 
     In one embodiment, a positional device suspension  115  suspends positional device casing  119  in drill head  18 , which may for instance have an inner diameter of about 1 inch. Positional device suspension  115  provides a physical separation (i.e. an annulus) between the outer surface of the positional device and the inner surface of the drill head, thereby allowing fluid to flow from drill tubing  19 , around and past positional device  113  through the annulus, and exit drill head  118  as a high pressure fluid jet. Furthermore, positional device  113  is suspended by suspension  115  in drill head  118  to allow the positional device to be shielded, to some extent, from any plastic and/or elastic deformation that may be experienced by drill head  118 . 
       FIG. 4 b    shows one embodiment where the positional device is suspended concentrically within the drill head; however, concentricity is not required. In a further embodiment, positional device  113  is suspended by suspension  115  in drill tubing  19 , rather than inside drill head  118 . Drill tubing  19  may have an inner diameter of, for example, about 1 inch. Suspending positional device  113 , as described above, allows fluid to flow around it and protects it to some extent from any deformation of the drill tubing. 
       FIG. 11  shows a sample drill head configuration usable with the above described systems and methods. In this embodiment, the drill head is configured to be steerable. A drill head  118  mountable on the distal end of drill tubing  19  has at least one side port  110  that is connected to a valve  111  having a side port inlet  112 . A positional device  113  is mounted inside drill head  18  or near the distal end of drill tubing  19 . In one embodiment, positional device  113  is mounted using positional device suspension  115 , which is as described with respect to  FIGS. 4 a  and 4 b   . In an alternative embodiment, the positional device may be suspended inside drill tubing  19 , instead of drill head  118 , as described above. 
     Positional device  113  is linked to valve  111  via a connection  114 . Connection  114  may be a wired connection or a wireless connection. Connection  114  is used to relay instructions to valve  111  to open or close. When valve  111  is open, a portion of the flow in drill head  118  is directed into inlet  112 , through valve  111  and exits port  110  as a high pressure fluid jet. This high pressure fluid jet generates a force that is sufficient to steer drill head  118  in a direction away from the fluid jet exiting from port  110 . Positional device  113  may include a processor, which may be pre-programmed with specific commands, such as keeping horizontal, heading in a downward direction, etc. Alternatively or additionally, the processor may be in communication with surface equipment to which it may transmit positional information about the drill head and from which it may receive steering instructions. 
     A sample embodiment of borehole placement relative to a wellbore is shown in  FIGS. 12 a  and 12 b   . Wellbore  202  is a substantially horizontal wellbore and may or may not include a casing  203 . At least one borehole  227  is drilled outwardly from wellbore  202 . The borehole  227  has a direction, a length, and a curvature. When viewed from one end of the wellbore  202  down the central long axis, as shown for example in  FIG. 12 b   , borehole  227   a  extends substantially horizontally away from the wellbore  202 . 
     In one embodiment, a plurality of boreholes  227  are positioned intermittently along the length of wellbore  202 , and the boreholes extend substantially horizontally outwardly from wellbore  202  in substantially the same horizontal plane. Preferably, the lowermost borehole is drilled first and the next borehole above the lowermost borehole is drilled, and so on, such that the boreholes  227  are drilled sequentially from the lowermost borehole to the uppermost borehole. 
     In a further embodiment, after a first borehole  227  is drilled and the drill head is retracted therefrom, the whipstock may be rotated about the long central axis of the bottom hole assembly by an angle, for example about 180 degrees, and the drill head is then once again advanced to drill a second borehole. The second borehole is at substantially the same axial location along the length of wellbore  202 , but extends at an angle away the first borehole due to the rotation of the whipstock. In the illustrated embodiment shown in  FIG. 12 b   , a first borehole  227   a  is angled apart from a second borehole  227   b  by about 180 degrees. 
     After one or more boreholes are drilled at an axial location of the wellbore, the bottom hole assembly  9  may be moved to another axial location along the wellbore, preferably in the direction towards the proximate end, where additional borehole(s) may be drilled as desired. Bottom hole assembly  9  is moved axially in wellbore  2  or casing  3  by shortening or lengthening work string  14 . If work string  14  is comprised of threaded casing, tubing, or pipe, then joints of the threaded casing, tubing, or pipe are removed or added to the proximate end of the work string to place the bottom hole assembly  9  at the desired axial position downhole. 
     The placement of a plurality of boreholes  227  extending from wellbore  202  may allow the wellbore to cover more surface area across a horizontal plane compared to that of a single lineal wellbore. 
     There are many possible applications and/or usages for a wellbore having a plurality of radially outwardly extending boreholes in the horizontal plane. For example, wellbore  202  may be one of the wells in a well pair in a steam assisted gravity drainage (SAGD) operation. Such an arrangement of boreholes in a SAGD well may be used to alter the shape and performance of the steam chamber. In another embodiment, wellbore  202  may be a well that is situated between a pair of SAGD wells. This borehole arrangement may enhance early well performance by accessing warm parts of the reservoir. Wellbore  202  may also be a well for use in cyclic steam stimulation (CSS). In steam processes, borehole configurations described herein may access additional reservoir and allow steam to reach and heat extended parts of the reservoir, thereby making the steam process more efficient and effective. 
     One or more of the plurality of boreholes may be positioned at or near the distal end of a vertical, deviated or horizontal wellbore. 
     Another sample embodiment of borehole placement relative to a wellbore is shown in  FIGS. 13 a  and 13 b   . Wellbore  202  is a substantially horizontal wellbore and may or may not include a casing  203 . At least one borehole  327  is drilled outwardly from wellbore  202 . The borehole  327  has a direction, a length, and a curvature. When viewed from one end of the wellbore  202  down the central long axis, as shown for example in  FIG. 13 b   , borehole  327   a  extends substantially vertically away from the wellbore  202 . 
     In one embodiment, a plurality of boreholes  327  are positioned intermittently along the length of wellbore  202 , and the boreholes extend substantially vertically outwardly from wellbore  202  in substantially the same vertical plane. Preferably, the lowermost borehole is drilled first and the next borehole above the lowermost borehole is drilled, and so on, such that the boreholes  327  are drilled sequentially from the lowermost borehole to the uppermost borehole. 
     In a further embodiment, after a first borehole  327  is drilled and the drill head is retracted therefrom, the whipstock may be rotated about the long central axis of the bottom hole assembly by an angle, for example about 180 degrees, and the drill head is then once again advanced to drill a second borehole. The second borehole is at substantially the same axial location along the length of wellbore  202 , but extends at an angle away the first borehole due to the rotation of the whipstock. In the illustrated embodiment shown in  FIG. 13 b   , a first borehole  327   a  is angled apart from a second borehole  327   b  by about 180 degrees. 
     After one or more boreholes are drilled at an axial location of the wellbore, the drilling components (i.e. drill tubing and drill head) may be moved to another axial location along the wellbore, preferably in the direction towards the proximate end, where additional borehole(s) may be drilled as desired. 
     The plurality of boreholes  327  extending from wellbore  202  may allow the wellbore to cover more surface area across a vertical plane compared to that of a single lineal wellbore. 
     There are many possible applications and/or usages for a wellbore having a plurality of radially outward extending boreholes in a vertical plane. For example, wellbore  202  may be a horizontal well. Many horizontal wells undulate upon drilling and may extend in and out of the desired level in the formation. Vertical plane boreholes can reach up or down to reach the desired level. In another embodiment the well may be a well in a steam assisted gravity drainage (SAGD) operation. The presence of horizontal shale layers can impede the orderly development of steam chambers. Vertical boreholes may be used to penetrate these shale layers which may help promote the development of steam chambers. In another embodiment, boreholes that are not necessarily vertical (e.g. curved, horizontal, diagonal, etc.) may be used to penetrate the shale layers. 
     Yet another sample embodiment of borehole placement relative to a wellbore is shown in  FIGS. 14 a , 14 b , and 14 c   . Wellbore  202  is a substantially horizontal, substantially vertical, or deviated wellbore and may or may not include a casing  203 . At least one borehole  427  is drilled outwardly from wellbore  202 . The borehole  427  has a direction, a length, and a curvature. When viewed from one end of the wellbore  202  down the central long axis, as shown for example in  FIG. 14 c   , borehole  427   a  extends away from the wellbore  202  at an angle between the vertical and the horizontal (an “oblique” angle). 
     In one embodiment, a plurality of boreholes  427  are positioned intermittently along the length of wellbore  202 , and the boreholes may extend substantially vertically, substantially horizontally, or obliquely outwardly from wellbore  202 . Preferably, the lowermost borehole is drilled first and the next borehole above the lowermost borehole is drilled, and so on, such that the boreholes  427  are drilled sequentially from the lowermost borehole to the uppermost borehole. When viewed from one end of the wellbore  202 , each borehole may or may not extend at the same angle as another borehole. 
     In a further embodiment, after a first borehole  427   a  is drilled and the drill head is retracted therefrom, the whipstock may be rotated about the long central axis of the bottom hole assembly by an angle, for example about 120 degrees, and the drill head is then once again advanced to drill a second borehole. The second borehole is at substantially the same axial location along the length of wellbore  202 , but extends at an angle away the first borehole due to the rotation of the whipstock. Additional boreholes may be drilled from substantially the same axial location in the wellbore by repeating this process of rotating the whipstock and drilling. For example, in the illustrated embodiment shown in  FIG. 14 c   , a first borehole  427   a  is angled apart from a second borehole  427   b  by about 120 degrees, and the second borehole  427   b  is angled apart from a third borehole  427   c  by about 120 degrees. 
     After one or more boreholes are drilled at an axial location of the wellbore, the drilling components (i.e. drill tubing and drill head) may be moved to another axial location along the wellbore, preferably in the direction towards the proximate end, where additional borehole(s) may be drilled as desired. 
     The plurality of boreholes  427  extending from wellbore  202  at various angles may allow the wellbore to cover more surface area compared to that of a single lineal wellbore and may allow the wellbore to be connected to other formations and/or structures in the earth, including for example other wellbores, tunnels, caves, etc. 
     Referring to  FIGS. 15 a  and 15 b   , a sample earth measurement system is shown. The system includes a measurement device  150  that is installed inside drill tubing  19  but does not block fluid flow therethrough. In one embodiment, as illustrated in  FIGS. 15 a  and 15 b   , measurement device  150  is mounted inside drill tubing  19  and is connected to the inner wall of drill tubing  19  by braces  151 . In the illustrated embodiment, braces  151  are spaced apart to provide passages  152 , formed between the outer surface of device  150  and the inner wall of drill tubing  19 , to allow fluid inside the drill tubing to flow past device  150  towards drill head  18 . 
     In a further embodiment, measurement device  150  may not be connected to the drill tubing  19  or drill head  18 , but rather is loose within the drill tubing or is tethered in some manner from above. 
     Measurement device  150  may be used to measure any of: fluid flow, stress, strain, position, pressures, temperatures, acoustical energy, magnetic flux, spontaneous potential, resistivity, other electrical signals, electromagnetic signals, radiation, such as radio signals, x-rays or gamma rays or any other such measurement as desired. In a sample embodiment, earth measurement device  150  is a fiber optics cable. For example, fluid flow may be measured using a temperature profile obtained via a fiber optics cable. Measurement device  150  may be connected to a remote site by a communication link  153 , which may be electrical, electro-magnetic or acoustical in nature, and wired or wireless, or measurements may be stored on board of the measurement device for subsequent download. 
     The measurement device may be placed downhole simultaneously as a borehole is being formed. The measurement device may also take measurements while the borehole is being formed. For example, a measurement device placement apparatus as described hereinbelow may be used to hydraulically inject the measurement device downhole, e.g. down the drill tubing or in the borehole. 
     Further, the measurement device may be placed downhole after the borehole has been drilled. This may be achieved by, for example, a measurement device placement apparatus as described hereinbelow. Before placing the measurement apparatus downhole via the drill tubing, and depending on the size of the measurement device, it may be necessary to remove the drill head to allow the measurement device to exit the distal end of the drill tubing. In one embodiment, the drill head is removed by raising the internal pressure within the drill tubing. Alternatively or additionally, a solid material or abrasives may be added to the drilling fluid to fracture or erode the drill head. 
       FIGS. 16 a  and 16 b    show a measurement device placement apparatus  20 ′ usable with the above described system  120  (shown in  FIG. 1 ), the device being configured for placing an earth measurement device. The placement apparatus  20 ′ has a proximate end connected to the connection string  21  and a distal end connected to drill tubing  19 . Placement apparatus  20 ′ has a lower conduit  126  near its distal end and an upper conduit  162  near its proximate end. The placement apparatus  20 ′ further includes a sliding sleeve  161  and a spring  163 . The placement apparatus  20 ′ has two positions: a standby position (as shown in  FIG. 16 a   ) and a launch position (as shown in  FIG. 16 b   ). 
     In the standby position, a measurement device  160  is placed inside placement apparatus  20 ′, near the proximate end thereof such that conduit  126  is below device  160 . Measurement device  160  may be held in place inside the placement apparatus by a retention mechanism, such as for example a magnet, spring, wire or cable, or a combination thereof. Spring  163  is provided above the measurement device and exerts a constant force on the device  160  in the direction of the drill tubing  19 . The spring  163  is selected with a spring constant that is not sufficient to overcome the retention mechanism holding device  160  in place. In one embodiment, sleeve  161  covers upper conduit  162  to restrict fluid flow therethrough, while lower conduit  126  is left open to allow fluid flow therethrough. 
     In the launch position, measurement device  160  is released from the retention mechanism. In one embodiment, the retention mechanism is an electromagnet, to which power is supplied to hold measurement device  160  in place. To release the measurement device, power to the electro magnet is cut off by a signal from the surface, thereby allowing spring  163  to push the device  160  towards the distal end of the placement apparatus  20 ′ and down drill tubing  19 . 
     In another embodiment, the retention mechanism is a wire or cable, and the wire or cable is tensioned to hold the measurement device in place. To release the measurement device, the tension in the wire or cable is released or lessened to allow the constant force exerted by spring  163  on device  160  to push the device  160  towards the distal end of the placement apparatus  20 ′ and down drill tubing  19 . 
     Optionally, in the launch position, sliding sleeve  161  moves towards the distal end of the placement apparatus to cover lower conduit  126  to restrict fluid flow therethrough, which consequently opens upper conduit  162  to allow fluid flow therethrough. With upper conduit open, fluid can flow therethrough into the placement apparatus from above the measurement device  160 , thereby exerting a hydraulic force on the device  160  to help push it into drill tubing  19  towards the distal end of drill tubing  19 . 
       FIG. 17  illustrates a sample measurement device placement apparatus usable with the above described system  220  (shown in  FIG. 2 ). Measurement device placement apparatus  180  comprises a first tubing  182 , providing a first flow path, and a second tubing  184 , providing a second flow path. Apparatus  180  is installable at an axial location between high pressure fluid source  24  and the proximate end of drill tubing  19 ′. Each of the first tubing and second tubing has an upper end and a lower end, with both ends in fluid communication with drill tubing  19 ′, such that when fluid is injected down drill tubing  19 ′ at least some fluid flows through measurement placement device  180 . 
     In the illustrated embodiment, the upper ends of both tubings  182  and  184  are connected to and in fluid communication with an inlet  176  and the lower ends of both tubings  182  and  184  are connected to and in fluid communication with an outlet  179 . Inlet  176  and outlet  179  are in the flow path of and in fluid communication with drill tubing  19 ′, with outlet  179  being downstream from inlet  176 . 
     First tubing  182  has a valve  171 . When valve  171  is open, fluid is allowed to flow through first tubing  182 . When valve  171  is closed, fluid flow through first tubing  182  is restricted. 
     Second tubing  184  has a first valve  172  and a second valve  173 . When each valve is open, the valve allows fluid flow therethrough. When the valve is closed, the valve restricts fluid flow therethrough. A measurement device  170  is placeable between the first valve  172  and the second valve  173 . In a sample embodiment, device  170  may be placed between the valves by using a first coupling  174  and a second coupling  175 , with the first coupling positioned between one end of the device  170  and the first valve  172 , and the second coupling positioned between the other end of the device and the second valve  173 . Valves  172  and  173 , and optionally couplings  174 ,  175 , provide a retention mechanism for keeping device  170  inside second tubing  184 . 
     Optionally, second tubing  184  includes a seal  178  between valves  172  and  173  which allows for the substantially fluidly-sealed passage of a control string  177  connectable to the measurement device  170 . When connected to device  170  through seal  178 , the control string  177  may be used to control the descent of the device  170  and/or to retrieve the device  170  back to the surface. Control string  177  may also be used to communicate with the device  170  and/or to retrieve data therefrom. The control string  177  may be for example a flexible wire, cable, continuous rod, coiled tubing, etc. 
     In operation, measurement device  170  is placed between valves  172  and  173  of second tubing  184 . As mentioned above, control string  177  may be connected to device  170 . Apparatus  180  has two positions: a standby position and a launch position. In the standby position, valves  172  and  173  are closed and valve  171  is open. Fluid passes through apparatus  180  and down drill tubing  19 ′ by entering inlet  176  and existing outlet  179  via tubing  182  past valve  171 . Because valves  172  and  173  are closed, the fluid bypasses the measurement device  170  and the measurement device is held in place inside apparatus  180 . 
     In the launch position, valve  171  is closed and valves  172  and  173  are opened. Fluid flows through apparatus  180  and down drill tubing  19 ′ by entering inlet  176  and flowing into tubing  184 , while bypassing tubing  182  due to the closure of valve  171 . The flow of fluid into tubing  184  pushes measurement device through the open valve  173  and eventually outlet  179 , and into the drill tubing  19 ′ below apparatus  180 . If control string  177  is connect to the device  170 , the control string stays connected to the device  170  as the device  170  exits the apparatus  180  and moves down the drill tubing  19 ′. 
     In one embodiment, the earth measurement device is fitted with an anchor for affixing itself to the earth, after it is deployed into the earth by the placement apparatus. 
     The above description regarding the placement and installation of the earth measurement device, especially with reference to  FIGS. 15 to 17 , is also applicable to earth manipulation devices, as described above. More specifically, an earth manipulation device may be placed downhole using a placement apparatus such as those described with respect to  FIGS. 16 and 17 . Further, the drill head may be removed as described above prior to placing the earth manipulation device. The earth manipulation device may include an anchor for affixing itself to earth after deployment. The earth manipulation device may also be connected to a control string. 
     With reference to  FIGS. 20 a  and 20 b   , a method for perforating casing and placing an extended borehole comprises positioning drill head  18  at the lower opening of whipstock  10 ; injecting drilling fluid with abrasive material into drill tubing  19 ; and ejecting the drilling fluid from drill head  18  as a high pressure abrasive cutting jet. The high pressure abrasive cutting jet cuts a hole in casing  3  of suitable size and shape to allow the drill head and drilling tubing to pass therethrough into the earth where an extended borehole is to be drilled. An extended borehole is more than a few feet in length. Drill head  18  may be built of suitable material to withstand abrasives, including for example, hardened steel, ceramics or tungsten carbide. Drill head  18  may also be capable of rotation to decrease cutting time and direct the high pressure abrasive cutting jet to form a clean, full sized hole for the passing therethrough of drill head  18  and drill tubing  19 . 
     The present invention may be used in wellbores in various applications including for example, steam assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), etc. 
     LIST OF ITEMS CONTAIN IN THE FIGURES 
     
         
         
           
               1 . Surface 
               2 . Wellbore 
               3 . Casing 
               4 . Wellhead flange 
               5 . Earth 
               6 . Wellhead control equipment 
               7 . Rotational Device 
               8 . Rotating flange 
               9 . Bottom hole assembly 
               10 . Whipstock 
               11 . Seal assembly 
               12 . Anchor 
               13 . Extendable work string 
               14 . Work string 
               15 . Hanger 
               16 . Sealing element 
               17 . Whipstock exit 
               18 . Drill head 
               19 . Drill tubing 
               19 ′. Drill tubing 
               20 . Flow-through device 
               20 ′. Placement apparatus 
               21 . Connection string 
               22 . Movement control device 
               23 . Inner annulus 
               23 ′. Inner annulus 
               24 . High pressure fluid source 
               25 . Inlet 
               26 . Conduit 
               27 . Borehole 
               28 . Seal 
               29 . Outlet 
               30 . Outlet valve 
               31 . Rotational device splines 
               32 . Work string splines 
               40 . Anchor piston 
               41 . Seal 
               42 . Annulus 
               60 . Centralizer 
               61 . Swivel 
               62 . Weight 
               63 . Drive Mechanism 
               70 . Wheel 
               71 . Tread 
               72 . Drive mechanism 
               80 . Seal 
               90 . Seal 
               91 . Deflection assembly 
               100 . BHA sensor/source 
               101 . Drill head or drill tubing sensor/source 
               102 . Upper section 
               104 . Lower section 
               110 . Side port 
               111 . Valve 
               112 . Side port inlet 
               113 . Positional device 
               114 . Communications link 
               115 . Positional device suspension 
               116 . Positional measurement components 
               117 . Power source 
               118 . Drill head 
               119 . Positional device casing 
               120 . System 
               126 . Lower conduit 
               150 . Measurement device 
               151 . Bracing 
               152 . Annulus 
               153 . Communications link 
               160 . Measurement device 
               161 . Sliding Sleeve 
               162 . Upper conduit 
               163 . Spring 
               170 . Measurement device 
               171 . Valve 
               172 . Valve 
               173 . Valve 
               174 . Coupling 
               175 . Coupling 
               176 . Inlet 
               177 . Control string 
               178 . Seal 
               179 . Outlet 
               180 . Apparatus 
               182 . First tubing 
               184 . Second tubing 
               190 . Earth 
               192 . Ice 
               194 . Fracture material 
               202 . Wellbore 
               203 . Casing 
               205 . Passage 
               210 . Passage 
               220 . System 
               227 . Borehole 
               327 . Borehole 
               427 . Borehole 
           
         
       
    
     The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. For US patent properties, it is noted that no claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”.