Patent Publication Number: US-8534379-B2

Title: Apparatus and methods for drilling a wellbore using casing

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 11/932,495, filed on Oct. 31, 2007, now U.S. Pat. No. 8,127,868, which is a continuation of U.S. patent application Ser. No. 10/772,217, filed on Feb. 2, 2004, now U.S. Pat. No. 7,334,650, which claims benefit of U.S. Provisional Patent Application Ser. No. 60/452,202, filed on Mar. 5, 2003, and U.S. Provisional Patent Application Ser. No. 60/444,088, filed on Jan. 31, 2003, which applications and patents are herein incorporated by reference in their entirety. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     Embodiments of the present invention generally relate to methods and apparatus for drilling and completing a well. More particularly, embodiments of the present invention relate to methods and apparatus for directionally drilling with casing. Even more particularly, embodiments of the present invention generally relate to the field of well drilling, particularly to the field of well drilling for the extraction of hydrocarbons from subsurface formations, wherein the direction of the drilling of the wellbore is steered and the need to determine the orientation of the drill bit within the earth is present. 
     2. Description of the Related Art 
     In conventional well completion operations, a wellbore is formed by drilling to access hydrocarbon-bearing formations. Drilling is accomplished utilizing a drill bit which is mounted on the end of a drill support member, commonly known as a drill string. The drill string is often rotated by a top drive or a rotary table on a surface platform or rig. Alternatively, the drill bit may be rotated by a downhole motor mounted at a lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed (e.g., pulled out), and a section of the casing is lowered into the wellbore. An annular area is formed between the string of casing and the formation, and a cementing operation may then be conducted to fill the annular area with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons. 
     It is common to employ more than one string of casing in a wellbore. Typically, the well is drilled to a first designated depth with a drill bit on a drill string. The drill string is then removed, and a first string of casing or conductor pipe is run into the wellbore and set in the drilled out portion of the wellbore. Cement is circulated into the annulus outside the casing string. Next, the well is drilled to a second designated depth, and a second string of casing or liner is run into the drilled out portion of the wellbore. The second string is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The second liner string is fixed or hung off the first string of casing utilizing slips to wedge against an interior surface of the first casing. The second string of casing is then cemented. The process may be repeated with additional casing strings until the well has been drilled to a target depth. In this manner, wells are typically formed with two or more strings of casing of an ever-decreasing diameter. 
     As an alternative to the conventional method, a method of drilling with casing is often utilized to position casing strings of decreasing diameter within a wellbore. Drilling with casing utilizes a cutting structure (e.g., drill bit or drill shoe) attached to the lower end of the same casing string which will line the wellbore. The entire casing string may be rotated by mechanical devices at the surface, which ultimately rotates the drill bit so that the drill bit drills into the formation. Once the well has been drilled to the target depth with the casing in place, the casing may be cemented to complete the well. Additional casing strings may be run through the first casing string and drilled further into the formation to form a wellbore of a second depth, and this process may be completed with subsequent additional casing strings. Drilling with casing is often the preferred method of well completion because only one run-in of the working string into the wellbore is necessary to form and line the wellbore. 
     Drilling with casing is useful in drilling and lining a subsea wellbore, particularly in a deep water well completion operation. When forming a subsea wellbore, the length of wellbore that has been drilled with a drill string is subject to potential collapse because of the soft formations present at the ocean floor. Also, sections of the wellbore intersecting regions of high pressure can cause damage to the drilled wellbore during the time lapse between the formation of the wellbore and the lining of the wellbore. Drilling with casing removes such time lapses and alleviates these problems. 
     An alternative drilling with casing method which is sometimes practiced instead of rotating the casing string to drill into the formation involves “jetting” or pushing the casing into the formation. Because hydraulic energy from nozzles in a drill bit is often sufficient to remove the formation without using bit cutters, it is often necessary to jet the pipe into the ground by forcing pressurized fluid through the inner diameter of the casing string concurrent with lowering the casing string into the wellbore. The fluid and the mud are thus forced to flow upward outside the casing string, so that the casing string remains essentially hollow to receive the casing strings of decreasing diameter which contribute to lining the wellbore. To accomplish jetting of the pipe, holes or nozzles may be formed through the lower end of the drill bit to allow fluid flow through the casing string and up into the annular space between the outside of the casing string and the wellbore. The holes may be essentially symmetric with respect to the drill bit so that a uniform amount of fluid is released along the diameter of the casing string. 
     In a further alternate drilling with casing method, a motor and a drill bit may be attached to a drill pipe and positioned at a terminal portion of the first casing string to allow rotational drilling of the casing string into the formation if desired, as well as allowing jetting by lowering the casing string into the formation to continue. The drill bit may be rotated while the first casing string is lowered into the formation to facilitate drilling the first casing string to a desired depth. Upon reaching the desired depth, the drill bit and the drill pipe may continue to drill down to a target depth to enable placement of the second casing string. When casing string reaches the target depth, the drill pipe, motor, and drill bit are pulled out of the wellbore while the casing string remains within the wellbore prior to cementing the casing string into the wellbore. The second casing string is run in and placed in the wellbore at the target depth, the motor system retrieved, and then the second casing string is cemented therein. Additional cost and time for completing a wellbore are inherent results of the current drilling with casing operation because the motor system must be retrieved from the wellbore prior to the cementing operation. 
     For various reasons, it may be necessary to deviate from the natural (e.g., substantially vertical) direction of the wellbore and drill a deviated hole. Drilling with casing techniques may also be utilized to drill a deviated hole, commonly referred to as “directional drilling with casing.” 
     In subsea drilling operations, a drilling platform is supported by the subterranean formation at the bottom of a body of water. The drilling platform is the surface from which the casing sections and strings, cutting structures, and other supplies are lowered to form a subterranean wellbore lined with casing. Each drilling platform represents a relatively significant cost. Also, governmental regulations allow only a limited number of platforms over a given surface area of the body of water. Accordingly, platforms must be spaced a predetermined distance apart for drilling subterranean wellbores. Additionally, each platform must only occupy a specified area of the surface of the body of water. Because only a certain number of platforms of a given dimension are allowed over a given surface area and because of the possibly prohibitive economic cost of multiple platforms, the number of wellbores drilled into the subterranean formation should be the maximum amount of wellbores which can be drilled into the subterranean formation from the permitted platforms. In this manner, hydrocarbon production is maximized, because increasing the producing wells increases the hydrocarbons obtainable at the surface of the wellbore. Each wellbore formed is therefore valuable as an independent producing well which directly increases production from the hydrocarbon source. 
     A common problem with drilling subsea wellbores is encountered due to the attempt to maximize hydrocarbon production by maximizing the number of wellbores drilled from slots in a platform of limited surface area. To drill the maximum amount of wells, the slots in the platform must exist at extremely close proximity to one another. The closer the proximity of the slots to one another, the more wellbores which can be drilled over a given surface area. Unfortunately, drilling the wellbores through the slots which are so close to one another leaves little room for even small directional deviations when the wellbore is not drilled directly downward into the subsea formation. Sometimes, the wellbores are accidentally deflected and drilled into one another, causing the wellbores to intersect. When two or more wellbores intersect, at least one wellbore is eliminated as an independent hydrocarbon production source. Thus, the allowed drilling area from the platform is reduced, causing a decrease in the production of hydrocarbons from the subsea formation. 
     To avoid the intersection of wellbores, the wellbores are often drilled at an angle from the slots in the platform. The wellbores drilled from the outermost slots on the platform are typically drilled at an angle outward from the platform, and the outward angle decreases progressively for the inward slots. Thus, wellbores should deviate slightly away from other wellbores to avoid interference with one another. Other instances exist when it would be desirable to directionally drill a wellbore, such as when drilling at an angle is necessary to reach a production zone. 
     Various methods of deviated drilling or nudging are currently practiced. One method involves pre-drilling a hole directionally with a drill bit on a drill string. In this method, a wellbore is drilled into the formation at an angle. The drill string is then removed and a string of casing placed into the pre-drilled hole. This method fails to prevent caving in of the wellbore between the time in which the hole is drilled and the time in which the casing is inserted into the wellbore. Moreover, the increased time and expense inherent in running the drill string and the casing string into the wellbore separately are disadvantages of this method. 
     Another method to accomplish the deviation involves first drilling a pilot hole which is smaller in diameter than the desired wellbore and angled in the desired direction. The hole is then enlarged to subsequently run the casing therethrough. This method involves at least two run-ins of the drill string to drill two holes of different diameter, increasing time, expense, and wellbore collapse potential. 
     There is a need, therefore, for apparatus and methods which are effective for drilling the casing into the formation in subsea well completion operations. There is a further need for nudging methods and apparatus which effectively deviate the subterranean wellbore while drilling the string of casing into the formation to prevent intersection of the wellbores. 
     Additionally, with the current drilling systems, drilling tools and casing strings need to be run and/or retrieved a plurality of times into and/or out of the wellbore to complete drilling, casing, casing expansion, and cementing operations, resulting in substantial costs and length of time for completing a well. Therefore, there is a need for an apparatus and method for performing drilling, casing, expansion, and cementing operations which substantially reduce the time and costs for completing a well. Particularly, there is a need for an apparatus and method for performing a drilling operation while casing the wellbore which allows a cement operation to be performed subsequently without having to first retrieve the motor system utilized for the drilling operation. Additionally, it would be desirable for the apparatus to be able to perform these operations in a variety of settings utilizing different equipment and tools. It would be desirable for the apparatus to perform deviated drilling or nudging operations which produce deviated wells. 
     As an alternate technique of drilling with casing which may be utilized instead of merely attaching a cutting structure to the casing, a bottomhole assembly (“BHA”) having a drill bit may be lowered into the formation with a casing. The drill bit is exposed through the lower end of the casing, and the BHA is secured to a bottom portion of the inner diameter of the casing. After lowering the casing into the formation, the drill bit is rotated either in a rotary mode by rotating the casing (e.g., utilizing the casing as a drill string) or in a slide mode by rotating the bit independently of the casing with a downhole drill motor. In either case, as the wellbore is extended, additional lengths of casing are added to the wellbore from the surface as the casing string advances with the wellbore. 
       FIG. 32  illustrates a conventional system for directional drilling with casing using a BHA  3100 . As illustrated, the BHA  3100  with a pilot drill bit  3108  is typically run through the casing  3104  (lining a wellbore  3102 ) and secured to a bottom portion of the casing  3104  with a casing latch  3106 . As previously described, the BHA  3100  may be operated in a rotary mode, by rotating the casing from the surface of the wellbore. As an alternative, the BHA  3100  may include a downhole motor  3112  above the pilot bit  3108 . As illustrated, the motor  3112  may be integral with a bent subassembly (or housing)  3114  to bias the pilot in the desired deviated direction (thus, the motor  3112  is commonly referred to as a “bent housing motor”). The deviated hole is drilled by adjusting the bent subassembly  3114  to point the pilot bit  3108  in the desired deviated direction. The trajectory of the deviated hole is typically dictated by the curvature that passes through the centers of the pilot bit  3108 , the bend in the motor  3112 , and the casing latch  3106 . 
     The deviated wellbore must be larger than the outside diameter of the casing  3104  to allow the casing to advance as the wellbore is extended. This is typically accomplished by utilizing an underreamer  3110  to enlarge a pilot hole drilled with the pilot bit  3108 . In other words, as the motor  3112  is operated, the pilot bit  3108  is rotated forming the pilot hole, which is then enlarged by the underreamer  3110  following behind. To run the BHA  3100  through the casing  3104 , expandable blades of the underreamer  3110  may be placed in a retracted position. The blades may be expanded prior to drilling the deviated hole and again retracted to retrieve the BHA  3100 , through the casing  3104 , after drilling. The BHA  3100  may also include sensing equipment  3109 , commonly referred to as a logging-while-drilling (LWD) or measuring-while-drilling (MWD), to take trajectory measurements (e.g., inclination and azimuth) and possibly formation measurements (e.g., resistivity, porosity, gamma, density, etc.) at several points along the wellbore which may be later used to approximate the wellbore path. MWD equipment usually contains the wellbore surveying sensors, while LWD equipment usually contains formation logging sensors. 
     The typical BHA  3100 , when connected to the casing  3104  with the casing latch  3106 , extends about 90 to 100 feet below the lower end of the casing  3104 . The extension of the BHA  3100  below the casing  3104  allows the pilot drill bit  3108  to form a rat hole (extended wellbore) below the lower end of the casing  3104 . The rat hole has a diameter larger than the outer diameter of the casing  3104  due to the underreamer  3110 . In the typical directional drilling process utilizing the BHA  3100 , the pilot bit  3108  is rotated to drill directionally the casing  3104  into a formation. The casing  3104  is then released from engagement with the casing latch  3106  of the BHA  3100 , and the casing  3104  is lowered over the BHA  3100  to the bottom of the rat hole. The BHA  3100  is eventually removed from the wellbore, and the casing  3104  is left in the wellbore. 
     The rat hole formation step and the step of lowering the casing  3104  over the BHA  3100  are required when using the current system of drilling with casing  3104  using a BHA  3100  because the bent housing  3114  must have a bend extending below the casing  3104  sufficient to introduce the desired trajectory into the deviated hole. Thus, the directional force for drilling the directional wellbore is supplied by the motor  3112  bend of the bent housing  3114  of the BHA  3100 , as the bent housing motor  3112  pushes directly on and against the side of the wellbore. Because the bent housing motor  3112  pushes against the side of the wellbore, a resultant force is caused on the opposite side of the underreamer  3110  and pilot drill bit  3108 . 
     While the system illustrated in  FIG. 32  may allow for the drilling of a deviated wellbore without removing casing, the system suffers a number of disadvantages. As an example, one disadvantage arises due to a lack of proper support between the casing latch  3106  and the point of contact of the pilot bit  3108 . As the typical length between the casing latch  3106  and the pilot bit  3108  may be in the range of between 40 feet to 120 feet, the BHA  3100  may buckle and lean towards a lower end of the deviated hole as downward force (i.e., “weight on bit”) is applied from the surface. This leaning is difficult to control and can severely affect the intended curvature and trajectory of the deviated hole. Further, without proper support, excessive lateral and axial vibrations in the BHA  3100  may reduce removal rate, reduce operating lifetime, and/or cause damage to the various components of the BHA  3110 , particularly when drilling in rotary mode. 
     A further disadvantage of the system of  FIG. 32  lies in the large length of the rat hole drilled below the lower end of the casing  3104 , into which the casing  3104  must be lowered over the BHA  3100 . Lowering the casing  3104  over the BHA  3100  in the 90-100 foot rat hole adds an extra step to the directional drilling with casing operation. Additionally, the system places unnecessary directional force directly on the BHA  3100 . Still another disadvantage in conventional drilling with casing systems is that the MWD  3109  does not provide real time survey information and, thus, the trajectory of the deviated hole can only be verified after drilling. This is unfortunate because real time feedback regarding the trajectory of the wellbore as it is being extended could be used to control the drilling process (e.g., adjust rotation speed of the bit, weight-on-bit, steer a rotary-steerable assembly or downhole motor, etc.), to control the trajectory of the wellbore. 
     When directionally drilling with a drill string, as the well is drilled, the bore direction must be checked or monitored, to ensure that the bore direction is not deviating from its intended direction. Such monitoring is typically provided by positioning a survey tool in a downhole location, in a rotationally fixed or known position, and monitoring signals therefrom to determine the orientation of the drill string in the earth. Where the drill string is pulled from the well after the wellbore is drilled, and the well is then cased, this is easily accomplished by fixing the survey tool in a subassembly in the drill string, and thus the survey tool is continuously in the borehole when the drill bit is at the bottom of the hole. However, where the drill string is later used as the casing, this is not practicable because the orientation tool is expensive, and therefore it is undesirable to abandon it in the well. Also, the survey tool, if left in the well, would create an obstruction to well fluid recovery, or for the passage of an additional drilling element therepast and thence through the end of the casing to continue drilling the borehole to greater extent, and thus would need to be drilled or milled out of the bore hole. Therefore, there exists a need in the art for a mechanism to provide downhole orientation tools in situations where the drill string is subsequently used, in situ, as the well casing, without creating an undue impediment to well fluid recovery, and without the economic consequences of leaving the survey tool in the hole after the well is complete. 
     SUMMARY OF THE INVENTION 
     Embodiments of the invention provide systems and methods for performing drilling, casing, and cementing operations which substantially reduce the time and costs for completing a well. More particularly, embodiments of the invention provide systems and methods for performing a drilling operation while casing the wellbore which allows a cement operation to be performed subsequently without having to first retrieve the motor system utilized for the drilling operation. 
     In one aspect, embodiments of the present invention provide a method for directing a trajectory of a lined wellbore comprising providing a drilling assembly comprising a wellbore lining conduit and an earth removal member, directionally biasing the drilling assembly while operating the earth removal member and lowering the wellbore lining conduit into the earth, and leaving the wellbore lining conduit in a wellbore created by the biasing, operating and lowering. 
     Embodiments of the invention are capable of performing these operations in a variety of settings utilizing different equipment and tools and perform deviated drilling or nudging operations which produce deviated wells. For example, embodiments of the invention may be utilized with an inter string, a bent pup joint, an orientation device, or without such tool. Furthermore, the apparatus may be utilized to perform a casing expansion operation concurrently with the retrieval of the motor system utilized for the drilling operation. 
     In one embodiment, an apparatus for drilling is provided. The apparatus comprises a motor operating system disposed in a motor system housing, a shaft operatively connected to the motor operating system, the shaft having a passageway, and a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft. The divert assembly facilitates switching of fluid flow to the motor operating system during a drilling operation and fluid flow through the passageway in the motor system during a cementing operation such that the motor system need not be removed to perform a cementing operation for the well. 
     Another embodiment provides an apparatus for drilling with casing, comprising a casing, a motor system retrievably disposed in the casing, and a drill face operably connected to shaft of the motor system. The motor system comprises a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; and a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft. 
     In another embodiment, a method for drilling and completing a well is provided. The method comprises pumping drilling fluid or drill mud to a motor system disposed in a casing; rotating an earth removal member, preferably a drill face, connected to the motor system; diverting fluid flow to a passageway through the motor system; and pumping cement through the passageway to the drill face. The motor system may be retrieved after the cement operation, and a casing expansion operation may be performed while retrieving the motor system. 
     An additional aspect of the present invention involves a method of initiating and continuing the formation of a wellbore by selectively altering the path of the casing string inserted into the formation as it travels downward into the formation. In one embodiment, the diverting apparatus comprises the casing string and cutting apparatus, along with a bend introduced into the casing string which influences the casing string to follow the general direction of the bend when forming a wellbore. 
     In another embodiment, the diverting apparatus comprises the casing string and cutting apparatus, as well as a diverter in the form of an inclined wedge releasably attached to a lower end of the casing string. In yet another embodiment, the diverting apparatus comprises the casing string, the cutting apparatus, and a fluid deflector. The diverting apparatus in yet another embodiment comprises the casing string, the cutting apparatus, the fluid deflector, and pads placed on the outer diameter of the casing string. 
     Another embodiment of the diverting apparatus also involves diverting fluid. In yet another embodiment, the diverting apparatus comprises the casing string, the cutting apparatus, and a second cutting apparatus disposed on the outer diameter of a portion of the casing string above the cutting apparatus. 
     A further aspect of the present invention is an apparatus and method for use with the diverting apparatus embodiments. The diverting apparatus is releasably connected to a drilling apparatus. In operation, after the wellbore path has been diverted by the diverting apparatus, the releasable connection between the drilling apparatus and the diverting apparatus is released. The drilling apparatus is then pulled upward to drill through the inner diameter of the casing string to remove any obstructions present inside the casing string which were previously used to divert the wellbore. Additional casing strings may then be hung off of the casing string, and further operations may then be conducted through the casing string. An even further aspect of the present invention involves a method and apparatus for surveying the path of the wellbore while penetrating the formation with the casing string to form the wellbore. 
     One embodiment provides a drilling assembly for extending a wellbore, the drilling assembly adapted to be run through casing lining the wellbore. The drilling assembly generally includes a casing latch for securing the drilling assembly to the casing, a bit attached to a bottom portion of the drilling assembly, a biasing member for providing the bit with a desired deviation from a center line of the wellbore, and at least one adjustable stabilizer for supporting the drilling assembly between the casing latch and the bit. 
     Another embodiment provides a drilling assembly for extending a wellbore, the drilling assembly attachable to casing lining the wellbore. The drilling assembly generally includes a bit disposed on a bottom portion of the drilling assembly, the bit adapted to be expanded from a first position for running through the casing to a second position for drilling a hole below the casing, the hole having a greater diameter than an outer diameter of the casing, and at least one stabilizer positioned between the bit and the bottom portion of the casing, the stabilizer adapted to be adjusted from a first position for running through a casing lining the wellbore to a second position for engaging an inner surface of the wellbore. 
     Another embodiment provides a method for drilling with casing. The method generally includes lowering a drilling assembly down a wellbore through casing, the drilling assembly comprising an adjustable stabilizer and one or more drilling elements, adjusting one or more support members of the stabilizer to increase a diameter of the stabilizer, and operating the drilling assembly to extend a portion of the wellbore below the casing, the extended portion having a diameter greater than an outer diameter of the casing. 
     The present invention generally provides methods and apparatus for positioning a downhole tool, such as a survey tool, in a downhole location in a fixed position relative to the drill string, both with respect to the distance between the survey tool and the drill bit, as well as the rotational alignment or orientation of the tool to the drill string and drill bit structure, and the capability to retrieve such tool before the well is used for production. In one embodiment, the drill string is provided with a drillable float sub, which includes an orientation member therein into which a survey tool, such as an orientation tool, is received in a known orientation when the survey tool is positioned in a downhole location within such drill string, and which is also useable as a cement float shoe, for traditional cementing operation to cement the casing in place in the borehole. The survey tool is thereby orientable in the drill string to enable meaningful orientation survey of the drill bit and bore orientation, either on a sampling or continuous basis. In another aspect, the survey tool may communicate information relating to orientation to the surface using via mud pulse telemetry, or other methods known to a person of ordinary skill in the art. 
     In a further embodiment, the float sub includes a muleshoe profile which receives a mating muleshoe profile of the survey tool. The muleshoe profile is positioned in a sleeve, into which the survey tool may be positioned, such that the muleshoe profile on the survey tool will align on the muleshoe profile of the float sub, thereby orienting the survey tool in the drill string. In a still further embodiment, the mule shoe profile of the float sub may include a secondary alignment member, to enable the landing of survey tools therein which do not include such mule shoe profile. 
    
    
     
       BRIEF DESCRIPTION 
       So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
         FIG. 1  is a schematic view of one embodiment of a system for drilling and completing a well in a formation under water. 
         FIGS. 2A and 2B  show a cross-sectional view of one embodiment of a hollow shaft motor drilling system disposed in a casing. 
         FIG. 3  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system illustrating a fluid divert operation. 
         FIG. 4  is a partial cross-sectional view of one embodiment of the divert system of  FIG. 3 . 
         FIG. 5  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system illustrating a cementing operation. 
         FIG. 6  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system illustrating a system retrieval operation. 
         FIG. 7  illustrates one embodiment of the drill system which may be utilized for a drilling and casing operation in which casing may be added during the operation. 
         FIG. 8  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system illustrating a drilling operation utilizing a bent pup joint. 
         FIG. 9  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system illustrating a drilling operation utilizing a bent pup joint and an inter string. 
         FIG. 10  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system illustrating a surveying operation. 
         FIG. 11  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system disposed in an expandable casing. 
         FIG. 12  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system disposed in an expandable casing illustrating an operation for expanding the casing after cementing. 
         FIG. 13  is cross-sectional view of an embodiment of a diverting apparatus of the present invention disposed within a subterranean wellbore. A diverter is located below a casing with an earth removal member attached thereto. 
         FIG. 14  is a cross-sectional view of an alternate embodiment of a diverting apparatus of the present invention disposed within a subterranean wellbore. A fluid deflector is disposed within the earth removal member attached to the casing. 
         FIG. 15  is a cross-sectional view of an alternate embodiment of the diverting apparatus of  FIG. 14  disposed within a subterranean wellbore. Stabilizer pads are disposed on the outer diameter of the casing. 
         FIG. 16  is a cross-sectional view of a further alternate embodiment of a diverting apparatus of the present invention disposed within a subterranean wellbore. A cutting apparatus in the form of an elongated coupling extends outward from the outer diameter of the casing. The right side of the casing axis in  FIG. 16  is cut away to show a threadable connection. 
         FIG. 17  shows an alternate embodiment of the diverting apparatus of the present invention having an eccentric stabilizer disposed thereon. 
         FIG. 18  is a cross-sectional view of a drilling apparatus for use with the diverting apparatus of the present invention in the run-in configuration. The drilling apparatus is shown after drilling a wellbore into the formation. 
         FIG. 19  is a cross-sectional view of the drilling apparatus of  FIG. 18  drilling through the diverting apparatus upon removal from the wellbore. 
         FIG. 20  is a cross-sectional view of the drilling apparatus of  FIG. 18  upon removal of the drilling apparatus after drilling through the diverting apparatus. 
         FIGS. 21 and 22  illustrate a process for drilling through casing. 
         FIGS. 23A and 23B  are perspective views of first and second ends of an embodiment of a drillable nozzle. 
         FIGS. 24A and 24B  are perspective view of first and second ends of an alternative embodiment of a drillable nozzle. 
         FIG. 25  is a section view of a first embodiment of a nozzle assembly disposed in a tool body. 
         FIG. 26  is a section view of a second embodiment of a nozzle assembly disposed in a tool body. 
         FIG. 27  is a section view of a third embodiment of a nozzle assembly disposed in a tool body. 
         FIG. 28  is a section view of a fourth embodiment of a nozzle assembly disposed in a tool body. 
         FIG. 29  is a section view of a tool body having nozzle assemblies disposed therein for drilling with casing. 
         FIG. 30  is a cross-sectional view of a lower end of an earth removal member having fluid passages therethrough. 
         FIG. 31  is a section view of a casing string capable of use in the present invention. 
         FIG. 32  illustrates an exemplary system for directional drilling according to the prior art. 
         FIGS. 33A-D  illustrate a system for directional drilling according to an embodiment of the present invention. 
         FIG. 34  is a flow diagram illustrating exemplary operations for directional drilling with casing according to an embodiment of the present invention. 
         FIG. 35  shows a sectional view of an alternate embodiment of a system for directional drilling with casing according to the present invention. An eccentric casing bias pad is shown on casing. 
         FIG. 36  shows a sectional view of a further alternate embodiment of a system for directional drilling with casing. 
         FIG. 37  is a cross-sectional view of another embodiment of a directional drilling assembly equipped with an articulating housing. 
         FIGS. 38A-B  show an exemplary articulating housing according to aspects of the present invention. 
         FIG. 39  shows another embodiment of a directional drilling assembly. 
         FIG. 40  shows the directional drilling assembly of  FIG. 45  after the BHA has reached the bottom of the wellbore. 
         FIG. 41  shows the directional drilling assembly of  FIG. 45  in operation. 
         FIG. 42  is a schematic view, in section, of a directional borehole being drilled. 
         FIG. 43  is a sectional view of a float sub in a downhole location indicated in  FIG. 42  and a sectional view of a survey tool receivable therein. 
         FIG. 43A  shows a side view of the survey tool of  FIG. 43 . 
         FIG. 44  is a sectional view of the float sub of  FIG. 43 , showing a survey tool in section, received and landed therein. 
         FIG. 45  is a sectional view of a float sub as in  FIG. 44 , showing an alternative embodiment of a survey tool shown partially in section to be received therein. 
         FIG. 46  is a partial sectional view of the float sub of  FIG. 45 , showing the survey tool in and landed on the float sub. 
         FIG. 47  shows a partial view of a float sub having a wellbore survey tool or sensor disposed therein. 
         FIG. 48  shows an embodiment of a survey tool assembly according to aspects of the present invention. 
         FIG. 49  shows the survey tool assembly of  FIG. 48  in the survey mode. 
         FIG. 50  shows the survey tool assembly of  FIG. 48  in the drilling mode. 
         FIG. 51  shows the bypass valve of the survey tool assembly of  FIG. 48  in the closed position. 
         FIG. 52  shows the bypass valve of the survey tool assembly of  FIG. 48  in the open position. 
         FIG. 53A  is a sectional elevation of an earth boring bit nozzle. 
         FIG. 53B  is a sectional view through the section y-y of  FIG. 53A . 
         FIG. 54  shows an alternate embodiment of a bit nozzle made substantially of a non-metallic metal. 
         FIG. 55  shows a cross-sectional view of an alternate embodiment of a diverting apparatus disposed within a subterranean wellbore for use in directional drilling. 
         FIG. 56A  is a cross-sectional view of a diverting apparatus used for expanding a casing. 
         FIG. 56B  is a cross-sectional view of the diverting apparatus of  FIG. 56A  in the process of expanding the casing. 
         FIG. 57  is an upward sectional view of an earth removal member for use in the present invention. 
     
    
    
     DETAILED DESCRIPTION 
     In the following embodiments of the present invention, the casing may be alternately jetted and rotated to form a wellbore. The rotation of the casing string may be accomplished either by rotating the entire casing or by rotating the cutting structure relative to the casing using a mud motor operatively attached to the casing. 
     Embodiments of the present invention provide systems and methods for performing drilling with casing operations which substantially reduce the time and costs for completing a well. More particularly, some embodiments of the present invention provide systems and methods for performing a drilling operation while casing the wellbore which allows a cement operation to be performed subsequently without having to first retrieve the motor system utilized for the drilling operation. 
       FIG. 1  is a schematic view of one embodiment of a system  100  for drilling and completing a well in a formation  112  under water  108 . Although the system  100  is shown in context of a deep sea drilling operation, embodiments of the invention may be utilized in drilling operations on land as well as under water  108 . As shown in  FIG. 1 , the system  100  includes a first, outer casing  185 , a second, inner casing  195 , and a drilling system  157 . The inner casing  195  is releasably connected, preferably releasably latched, onto the outer casing  185 , and the drilling system  157  is releasably connected, preferably releasably latched, in the inner casing  195 . The drilling system  157  includes an earth removal member, preferably in the form of a drill bit or drill shoe  167  which protrudes outside a terminal portion  147  of the outer casing  185 . An inter string or drill string  165  connects the drilling system  157  to a ship or platform  155  at the surface of water  108 . The system  100  may be utilized to drill and case a well in the formation  112  under the sea floor or mud line  160 . 
     Typically, casing  185  or  195  is made up of sections of casing. Each section of casing has a pin end and a box end for threadedly connecting to another section of casing above and/or below the casing section. A casing string includes more than one section of casing threadedly connected to one another. As used herein, casing may include a section of casing or a string of casing. 
       FIGS. 2A and 2B  show a cross-sectional view of one embodiment of a hollow shaft motor drilling system  200  disposed in a casing  219 . The hollow shaft motor drilling system  200  illustrates one embodiment of the drilling system  157 , and the casing  219  is representative of the second casing  195 . The hollow shaft motor drilling system  200  generally comprises a casing latch  211 , a hollow shaft motor  221 , and a drill shoe  270 . The hollow shaft motor drilling system  200  may include a guide assembly  203  attached to the casing latch  211 . In one embodiment, the guide assembly  203  includes a conical portion  204  and a tubular portion  206 . The conical portion  204  guides mechanical devices run in from the surface or drilling fluid or drill mud into the tubular portion  206 . Such mechanical devices may include an inter string or drill string  207 , a closing ball, a latching dart  286  (see  FIGS. 5 and 6 ), and other devices attached to a wireline. The tubular portion  206  also provides a plurality of receptacle seats such as a spear seat  208  for receiving a stinger attached to an inter string  207  and a orientation tool landing seat  209  for receiving an orientation tool for performing a survey. The tubular portion  206  is attached to the casing latch  211  and provides a fluid passageway which connects to a fluid passageway in the casing latch  211 . 
     The casing latch  211  is fixedly attached to the hollow shaft motor  221  and provides a mechanism for securing the hollow shaft motor drilling system  200  against an interior surface of the casing  219 . In one embodiment, the casing latch  211  includes a set of gripping members, preferably retractable slips  212 , disposed between an upper body  214  and a lower body  216 . The lower body  216  includes one or more angled surfaces  218  which urge the slips  212  outwardly when the slips  212  are pushed against the angled surfaces  218 . A locking mechanism, preferably a locking ring  213 , is utilized to keep the slips  212  in the set position against the interior surface of the casing  219  once the slips  212  are extended. The locking ring  213  may be spring loaded by a coil spring  222  and released from a locking position by breaking one or more release shear pins  224 . 
     An upper cup seal assembly  226  is disposed on an outer surface of the upper body  214  to provide a seal between the casing latch  211  and the casing  219 . The casing latch  211  includes an axial tube  228  which provides a fluid passageway through the casing latch  211  to the hollow shaft motor  221 . One or more bypass ports  217  may be disposed on the axial tube  228  and on the upper body  214  to facilitate fluid flow (e.g., drilling fluid or drill mud) during retrieval of the hollow shaft motor drilling system  200 . The lower body  216  of the casing latch  211  is attached to the hollow shaft motor  221 . 
     The hollow shaft motor  221  provides the mechanism for rotating the drilling member  270  (e.g., a rotating drill face on a drill shoe). In one embodiment, the hollow shaft motor  221  includes a housing  242 , a motor operating system  244 , a shaft  246 , and a fluid divert assembly  248 . The housing  242  includes an upper opening  249  which provides the connection to the casing latch  211  and continues the axial passageway  228  from the casing latch  211 . A lower cup seal  251  may be disposed on an outer surface of the housing  242  to provide a seal against the interior surface of the casing  219 . 
     In one embodiment, the motor operating system  244  is a hydraulic motor system which is operated by fluids (e.g., drilling fluid or drill mud) pumped through the motor operating system  244 . The motor operating system  244  may be a stator system or a turbine system and turns the shaft  246 . The shaft  246  is disposed axially along the hollow shaft motor  221  and includes an axial passageway  223  which is connected to the axial passageway  228  from the casing latch  211 . The fluid divert assembly  248  is disposed at an upper portion of the axial passageway  223  to divert fluids into the motor operating system  244  or to direct fluid flow through the passageway  223 . 
     In one embodiment, the fluid divert system  248  includes a closing sleeve  252 , one or more divert ports  254 , and a shear ring  256 . In normal drilling operation, the shear ring  256  keeps the closing sleeve  252  in the open position which allows the divert ports  254  to divert fluids into the motor operating system  244 . To move the closing sleeve  252  to the closed position (i.e., where the divert ports  254  are blocked from directing fluids into the motor operating system  244 ), the shearing ring  256  is broken by mechanical means, for example, by dropping a ball  261  (see  FIG. 3 ) from the surface. The fluid divert system  248  also includes a rupture disk  258  and an extrudable ball seat  260  for facilitating moving the closing sleeve  252  to a closed position which shuts off fluid delivery to the motor operating system  244  and diverts fluid flow through the axial passageway  223  in the shaft  246 . 
     The extrudable ball seat  260  includes a seat opening and may be made from a frangible material such as brass, aluminum, rubber, plastic, mild steel, and other material which may be opened, extruded or expanded when a predetermined pressure is applied to the seat opening. For example, when a ball  261  (see  FIG. 3 ) has been dropped into the extrudable ball seat  260  with fluids continually pumped behind the ball  261 , pressure builds up against the extrudable ball seat  260 , and when a predetermined pressure has been reached, the shear ring  256  breaks and the sleeve  252  shifts down and closes port(s)  254 . Next, a second predetermined pressure is reached and the extrudable ball seat  260  opens up and allows the ball  261  to travel through the seat opening, with sufficient force to break through the rupture disk  258 . The rupture disk  258  may be made from a flangeable material which, when ruptured or broken by a ball  261 , opens up in a clover leaf pattern generally and does not break off into pieces. When a rupture disk  258  has been broken, fluid flow is directed through the passageway  223  in the shaft  246  to the drill shoe  270 . 
     The drill shoe  270  is disposed at a terminal portion of the casing  219 . The drill shoe  270  includes a mounting portion  272  for connecting to the end of the casing  219 . The mounting portion  272  secures the drill shoe  270  to the casing  219 . The drill shoe  270  includes a rotating drill face  274  which is rotatably disposed on the mounting portion  272 . A set of bearings  276  is disposed between the mounting portion  272  and the rotating drill face  274  to facilitate rotational movement of the rotating drill face  274 . Alternatively, a ball joint (not shown) can be utilized instead of the bearings  276 . Utilizing a ball joint would facilitate adjustment of the drill face  274  angle (or azimuth of the bit face) relative to the axis of the casing  219 . A spindle  278  is attached to the rotating drill face  274 . The spindle  278  is connected to a terminal portion of the shaft  246  of the hollow shaft motor  221  which provides the rotational movement to the rotating drill face  274 . The spindle  278  includes a central passageway  229  which is connected to the axial passageway  223  in the shaft  246  of the hollow shaft motor  221 . The central passageway  229  facilitates fluid flow (e.g., drill mud or cement) to one or more nozzles  227  (preferably bit nozzles) in the rotating drill face  274 . The nozzles  227  allow fluid flow out of the drill face  274  and into the annulus between the casing  219  and the formation to facilitate drilling operations and cementing operations. A dart seat  282  is positioned on the central passageway  229  for receiving a dart which may be utilized to seal the central passageway  229 . 
       FIGS. 2A and 2B  illustrate one embodiment of the drill system  200  which may be utilized for a drilling and casing operation in which the casing  219  is of a set length and the drill pipe (or inter string)  207  may be added from the surface during the operation. In one embodiment, the hollow shaft motor drilling system  200  may be utilized in offshore deep sea drilling in which the distance from the water surface to the sea floor is greater than the length of the casing  219 . The hollow shaft motor drilling system  200  may be disposed on an inner casing  195  of a nested casing configuration, as shown in  FIG. 1 . The inner casing  195  may be latched to an outer casing  185  utilizing a J-slot mechanism (not shown). In one embodiment, the outer casing  185  is a 36-inch diameter casing, while the inner casing  195  is a 22-inch diameter casing, and a drill shoe  270  or  135  having a 26-inch drill surface or drill bit is attached to the tip of the inner casing  195 . The nested casing configuration is attached to the surface platform  155  utilizing an inter string  165  and lowered down to the sea floor  160 . 
     To begin the drilling operation, referring again to  FIGS. 2A and 2B , drilling fluid or drill mud is pumped from the surface through the inter string  207  attached to the hollow shaft motor drilling system  200  to provide the hydraulic power to drive the motor operating system  221  which rotates the drill shoe  270 . The outer casing  185  (see  FIG. 1 ) is jetted/drilled to a first target depth with the inner casing  195 ,  219  latched inside. The outer casing  195 ,  219  may be directionally drilled into the formation using any of the embodiments shown in  FIGS. 13-20  and described below. By nudging the outer casing  195 ,  219 , the direction of the wellbore may be started so that subsequent casing may be drilled further into the wellbore at an angle. 
     Once this first target depth has been reached, the inner casing  195 ,  219  is released from the outer casing  185  (e.g., by turning the inner casing  195 ,  219  through the J-slot mechanism) and continued to be drilled/jetted down until a second target depth is reached. The methods and apparatus of  FIGS. 13-20  described below may also be used on the outer casing  185 . Once the inner casing  195 ,  219  has reached the target depth, as shown in  FIG. 3 , a ball  261  is dropped from the surface through the casing  195 ,  219  and into the extrudable ball seat  260  to shut off fluid flow to the motor operating system  244  and divert the flow to the passageway  223  in the shaft  246 . The ball  261  is then pressured from the surface to a first predetermined pressure to shear ring  256 , thus moving the sleeve  252  to a closed position. At a second predetermined pressure, ball  261  extrudes through the seat  260 , then impacts and breaks rupture disc  258 , as shown in  FIG. 3 . 
       FIG. 3  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system  200  illustrating a fluid divert operation.  FIG. 4  is a partial cross-sectional view of one embodiment of a divert system  248  in a closed position in which the ports  254  are closed off from delivering fluid flow to the motor operating system  244 . To open fluid flow to the passageway  223  in the shaft  246 , fluid (e.g., drilling fluid, drill mud, or cement) may be pumped in behind the ball  261  to build up pressure against the ball seat  260 , and once sufficient pressure is reached, the shear ring  256  breaks and the sleeve  252  closes the port(s)  254 . When a second predetermined pressure is reached, the ball  261  shoots through the extrudable ball seat  260  and breaks through the rupture disk  258 , allowing fluid flow through the passageway  223 . The ball  261  travels through the passageway  223  and falls into a cavity  284  (shown in  FIG. 2 ) in the spindle  278 . Once the divert system  248  is set to direct fluid flow through the passageway  223 , a cementing operation may be performed. 
       FIG. 5  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system  200  illustrating a cementing operation. A physically alterable bonding material, preferably cement, may be pumped from the surface through hollow shaft motor drilling system  200  and through one or more bit nozzles  227  in the drill face  274 , filling or partially filling gaps between the casing  219  and the formation. After sufficient cement has been pumped through to cement the casing  219  in place, a latching dart  286  is inserted from the surface to close off the central passageway  229  in the spindle  278 . The latching dart  286  is utilized to prevent back flow through the central passageway  229  in the spindle  278  and to stop flow through the one or more bit nozzles  227  in the drill face  274 . Alternatively, instead of or in addition to the latching dart  286 , a float valve may be utilized to prevent back flow fluid pumped down through the drill shoe  270 . The latching dart  286  is displaced down to the dart seat  282  by mud pumped in behind the dart  286  from the surface. Once the latching dart  286  is secured onto the dart seat  282 , a system retrieval operation may be performed to retrieve the motor system  221  and the casing latch  211 . 
       FIG. 6  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system  200  illustrating a system retrieval operation. With the latching dart  286  in the dart seat  282 , the slips  212  on the casing latch  211  may be released by a mechanical jerking action (e.g., utilizing the inter string  207  or a wireline) which shears the releasing shear pin  224 . Once the releasing shear pin  224  is broken, the slips  212  collapse inwardly and release from the interior surface of the casing  219 , and the motor system  221  and the casing latch  211  may be retrieved (e.g., physically picked up) from the surface by retracting or pulling up on the inter string  207 . In the retrieving operation, the shaft  246  of the motor system  221  is detached from the spindle  278  of the drill shoe  270 , leaving the latching dart  286  in the dart seat  282 . As the casing latch  211  is moved up toward the surface, the bypass ports  217  may be opened to allow remaining mud in the system to flow through the bypass ports  217  into the casing  219 . If a float valve is utilized in the drill shoe  270 , the motor system  221  may be retrieved utilizing mechanical means other than the inter string (or drill pipe)  207 , such as, for example, cable wireline, coiled tubing, coiled sucker rod, etc. 
     As described above, the hollow shaft motor drilling system  200  facilitates drilling with casing and enables cementing the well in one single trip down without having to first retrieve the motor system  221  and the drill bit  270 . Considerable time is reduced in drilling and casing a well, resulting in substantial economic saving. Embodiments of the hollow shaft motor drilling system  200  may be utilized in a variety of applications. 
       FIG. 7  illustrates one embodiment of the drilling system  200  which may be utilized for a drilling and casing operation in which casing may be added during the operation. To begin the drilling operation, drilling fluid or drill mud is pumped from the surface through the inner diameter of the casing  219  to the hollow shaft motor drilling system  200  to provide the hydraulic power to drive the motor operating system  221  which rotates the drill shoe  270 . The casing  219  is jetted/drilled to a target depth. The ability to drill a hole without rotating the casing  219  while adding casing at the surface may reduce the time needed to perform the drilling operations. Alternatively, the casing  219  may be rotated by surface equipment (e.g., top drive, rotary table, etc.) during the jetting/drilling operation without or in addition to rotating the drill shoe  270 . Once the casing  219  has reached the target depth, a fluid divert operation, a cementing operation, and a retrieval operation may be performed, similar to the description above relating to  FIGS. 3-6 , except fluids are pumped down from the surface through the interior diameter of the casing  219  instead of the inter string  207 . 
     Embodiments of the invention may also be utilized to perform directional drilling.  FIG. 8  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system  800  illustrating a drilling operation utilizing a bent pup joint  802 . As shown in  FIG. 8 , the motor system  221  and the drill shoe  270  are latched onto a bent pup joint  802 . The bent pup joint  802  is threaded onto casing with casing  219  being rotated at the surface during straight hole sections and being slid during directional sections to drill the casing  219  into the formation at an angle α.  FIG. 9  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system  800  illustrating a drilling operation utilizing a bent pup joint  802  and an inter string  207 . This embodiment facilitates addition of inter string  207  to a bent pup joint assembly  800  from the surface. The casing  219  is of a set length while drill pipe (e.g., inter string)  207  is added at the surface. Both  FIGS. 8 and 9  shows a bent angle α (e.g., one degree bend) from the main drilling axis. Utilizing a bent pup joint  802  allows for drilling a deviated hole or performing a nudging operation, without having to depend on a jetting/sliding operation. Typically, to keep the drilled hole straight, the casing  219  is rotated when the casing  219  is not sliding or in a slide mode. In an alternate embodiment, the inter string  207  may not be attached during the drilling operation, but may be utilized to retrieve the motor system  221 . When an inter string  207  is utilized, it would be advantageous (e.g., faster) to perform the cementing operation utilizing the inter string  207 . 
     Embodiments of the invention may be utilized to perform a survey operation to determine the direction of drilling.  FIG. 10  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system  200  illustrating a surveying operation. At any time during the drilling operation, if a survey is needed to determine or confirm the direction of drilling, a survey operation may be performed by lowering an orientation device  1010  into the guide  204 . In a survey operation, the inter string  207 , if utilized, is withdrawn to allow usage of the orientation device  1010 . The orientation device  1010  is inserted into the landing seat  209  to determine the azimuth deviation of the drilled well. After the survey has been performed, normal drilling operations may be resumed and corrections may be made to direct or deviate the well in the desired direction. The surveying operation may also be conducted while drilling in a measuring-while-drilling operation, so that the angle of the casing may be continuously adjusted while drilling without interrupting the drilling and casing operation. 
     Embodiments of the invention may be utilized in a drilling with casing operation in which the casing  1102  may be cemented and expanded with the same run of the casing  1102 .  FIG. 11  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system  1100  disposed in an expandable casing  1102 . The hollow shaft motor drilling system  1100  includes similar components as the drilling system  200  described above except the housing  1142  of the hollow shaft motor drilling system  1100  is enlarged (as compare to housing  242 ) to conform with an enlarged terminal portion  1103  of the expandable casing  1102 . Also, the casing latch  1110  does not include bypass ports such as the bypass ports  217  on the casing latch  211 . Drilling and cementing operations as described above may be performed similarly utilizing the hollow shaft motor drilling system  1100 . After the drilling and cementing operations have been performed, the expandable casing  1102  may be expanded or enlarged from the inside utilizing the enlarged housing  1142 . 
       FIG. 12  is a cross-sectional view of one embodiment of a hollow shaft motor drilling system  1100  disposed in an expandable casing  1102  illustrating an operation for expanding the casing  1102  after cementing. After the cement has been pumped into the annulus between the casing  1102  and the formation and the latching dart  1186  has been placed into the dart seat  1182 , the slips  1112  on the casing latch  1110  are released to allow retrieval of the motor system  1140  which causes expansion the casing  1102 . The casing  1102  may be expanded by mechanically pulling up the enlarged housing  1142  (e.g., utilizing an inter string such as  207 ) or by pumping fluids (e.g., mud) down to push the housing  1142  up, or by a combination of both of these methods. In one embodiment, as the motor system  1140  is pulled up (e.g., utilizing inter string), mud is pumped through the passageways  1128  and  1150 , filling the space inside the casing  1102  between the housing  1142  and the spindle  1178  of the drill shoe  1170 . With more mud being pumped down from the surface, pressure builds up between the housing  1142  and the spindle  1178  and pushes the housing  1142  upwards. The housing  1142  pushes against the interior surface of the casing  1102 , expanding the casing  1102  as the housing  1142  travels upwardly toward the surface. With the retrieval of the motor system  1140 , the casing  1102  is expanded to a larger internal diameter. Furthermore, since the cement between the casing  1102  and the formation has just recently been pumped there and has not set or dried, expansion of the casing  1102  squeezes the cement into remaining voids in the formation, resulting in a better seal or stronger cement job of the casing  1102  in the formation. 
     With the embodiments of  FIGS. 1-12 , additional casing (not shown) may be used to drill through the remaining tools and any cement in the cemented casing  202 ,  802 ,  1102 . The additional casing may include the motor drilling system therein, as described in relation to  FIGS. 1-12 . Additionally, the additional casing may be cemented into the formation and expanded by the motor drilling system. 
     In an additional aspect of the present invention, the motor drilling system  200  or  1100  described in relation to  FIGS. 1-12  may be used in conjunction with preferentially deflecting a casing in the form of a casing section or casing string in the wellbore in a direction using the casing, as shown and described in relation to  FIGS. 13-20 . In the embodiments described herein, “casing string” refers to one or more sections of casing. More than one sections of casing are threadedly connected to one another.  FIG. 13  shows a diverting apparatus  10  of the present invention disposed in a wellbore  30 . The wellbore  30  is a hole drilled in a subterranean formation  20 . The diverting apparatus  10  comprises a cutting apparatus  50  connected to a lower end of a casing string  40 . The casing string  40  is inserted into the formation  20 . The cutting apparatus  50  has perforations  55  therethrough which allow fluid circulation between the wellbore  30  and the casing string  40 . 
     The diverting apparatus  10  also comprises a diverter  60  connected to the lower end of the casing string  40  below the cutting apparatus  50 . The diverter  60  is connected to the lower end of the casing string  40  by a releasable attachment  65 . The releasable attachment  65  is preferably a shearable connection. The diverter  60  is preferably an inclined wedge attached to a portion of the casing string  40  by the releasable attachment  65 . The diverter  60  has securing profiles  70  disposed at the lower end thereof, which are slots formed within the diverter  60  for grabbing the formation  20 . The securing profiles  70  provide traction for the diverter  60  while the casing string  40  is penetrating the formation  20 , preventing rotational movement of the diverter  60 . 
     Optionally, the casing string  40  of the diverting apparatus  10  may have a landing seat  45  disposed therein above the cutting apparatus  50 . The landing seat  45  is a slot in which to fit a survey tool (not shown). Placing the survey tool into the landing seat  45  allows the angle at which the wellbore  30  is being drilled with respect to a surface  5  of the wellbore  30  to be ascertained and permits appropriate adjustment to the direction and/or angle of the wellbore  30 . To determine the angle at which the wellbore  30  is being drilled, the survey tool is first calibrated at the surface  5 . The survey tool is then run through the casing string  40  and into the landing seat  45 . Once it is secured within the landing seat  45 , a second reading of the survey tool is taken, which reveals the angle at which the wellbore  30  is drilled in relation to the surface  5 . The survey tool and landing seat  45  permit continuous drilling with casing while surveying the conditions and direction of the wellbore  30 . Adjustment to the direction of the wellbore  30  can be made during the drilling operation. The survey tool is preferably a gyroscope, which is known to those skilled in the art. 
     In operation, the diverting apparatus  10  is drilled into the formation  20  by axial movement to form a wellbore  30 . As the casing  40  penetrates the formation  20  to form the wellbore  30 , pressurized fluid is introduced into the casing  40  concurrent with the axial movement of the casing  40  so that fluid flows downward through the inner diameter of the casing  40 , through the one or more nozzles  55 , into the wellbore  30 , and up through an annular space  90  between the outer diameter of the casing  40  and the inner diameter of the wellbore  30  to the surface  5 . Once the diverting apparatus  10  has reached a predetermined depth within the wellbore  30 , in one embodiment a downward axial force calculated to release the releasable attachment  65  is exerted on the casing  40  from the surface  5 . The releasable attachment  65  releases so that the casing  40  with the cutting apparatus  50  attached thereto is moveable in relation to the diverter  60 . Other embodiments not shown may allow the dropping of an object from the surface, such as a ball or dart, to release the diverting apparatus  10  from the casing  40 . Other embodiments not shown may also include signals from the surface such as mud pulses to cause the release of the diverting apparatus  10  from the casing  40 . Still other embodiments not shown may include the use of hydraulic pressure applied from the surface through the casing  40  or through a separate line such as an inter string to cause the release of the diverting apparatus  10  from the casing  40 . Downward force from the surface  5  is applied to the casing  40 , urging the casing  40  along an upper side  61  of the diverter  60 , which remains at the same position within the wellbore  30 . The obstruction caused by the diverter  60  forces the lower end of the casing  40  to deviate from its original axis at an angle essentially consistent with the slope of the upper side  61  of the diverter  60 , causing the casing  40  to move preferentially in a direction. The survey tool may be placed within the landing seat  45  to determine the point at which the desired deviation angle has been reached. Once the desired angle of deviation is accomplished, a setting operation is conducted, as setting fluid such as cement is introduced into the casing  40  from the surface  5 . The setting fluid flows downward into the casing  40 , through the one or more nozzles  55 , into the wellbore  30  and up into the annular space  90 . The setting fluid then fills the annular space  90  to anchor the casing  40  within the wellbore  30 . The diverter  60  remains permanently within the wellbore  30 . 
     Additional casing (not shown) may then be drilled into the formation  20  below the casing  40  by rotational and/or axial force. The casing  40  serves as a template for the angle followed by the additional casing strings, so that the additional casing strings are biased in the preferential direction. Because the additional casing strings are hung from the casing  40 , the additional casing strings divert in the desired direction at the angle in which the casing  40  was biased. A setting operation with setting fluid is conducted on additional casing strings as described above in relation to the casing  40 . 
       FIG. 14  shows an alternate embodiment of a diverting apparatus  110  of the present invention. The diverting apparatus  110  is used to form a wellbore  130  in a formation  120 . The diverting apparatus  110  comprises a casing string  140  wherein a bend is introduced into a portion of the casing string  140  to deflect the path of the wellbore  130  according to the bend in the casing string  140 . The casing string  140  is used to penetrate the formation  120 . The bend is not co-axial relative to the axis of the casing string  140 . An arc is therefore integrated into the casing string  140  to urge the casing string  140  to form the diverted path for the wellbore  130 .  FIG. 14  illustrates introducing the bend into the casing string  140  by connecting component parts of the casing string  140  by male threads  135  which engage female threads  125  to form a threadable connection. In the shown embodiment of the diverting apparatus  110 , the male and female threads  135  and  125  are oriented on the casing string  140  so that the connection of the component parts disposes a lower portion  136  of the casing string  140  below the threadable connection at an angle off of the vertical axis, so that the lower portion  136  of the casing string  140  is at an angle with respect to an upper portion  137  of the casing string  140 . The female threads are not cut co-axially into the lower portion  136  of the casing string  140 , so that the lower portion  136  of the casing string  140  is bent or slanted relative to the upper portion  137  of the casing string  140 . As shown in  FIG. 14 , the lower portion  136  of the casing string  140  is at an angle biased to the right of the upper portion  137  of the casing string  140 , which is essentially vertically disposed relative to a surface  105  of the wellbore  130 . 
     The diverting apparatus  110  further comprises a cutting apparatus  150  connected to a lower end of the casing string  140 . At a location which is off center from the vertical axis of the casing string  140 , one or more fluid deflectors  175  are formed through the casing string  140  and the cutting apparatus  150 . The fluid deflector  175  is preferably one or more nozzles through the casing string  140  and cutting apparatus  150  which is angled outward with respect to the axis of the casing string  140  in the same direction in which the fluid deflector  175  is biased. The fluid deflector  175  is biased and angled in the direction in which it is desired for the wellbore  130  to be diverted, which is the preferential direction of the wellbore  130 . 
     Also part of the diverting apparatus  110  is a float sub  115 . A float sub  115  is a tubular-shaped body which prevents fluid from flowing back up through the inner diameter of the casing string  140  after the setting fluid has been forced downward into the casing string  140  for the setting or cementing operation (described below). Also, the float sub  115  prevents fluid from flowing from the formation  120  in the casing string  140  to reduce frictional resistance while running the casing string  140  into the formation  120 . The float sub  115  comprises a ball seat  102  with a ball  101  initially disposed therein, as shown in  FIG. 14 . The ball seat  102  may also be any type of one-way check valve, include a flapper-type valve. The diverting apparatus  110  further includes a landing seat  145  for a survey tool (not shown), which operates in the same manner as described above with respect to the landing seat  45  of  FIG. 13 . The float sub  115  and the landing seat  145  are preferably made of drillable material such as aluminum or plastic, so that they may be drilled through after the casing string  140  is set within the wellbore  130 . 
       FIG. 15  is an alternate embodiment of the diverting apparatus  110  of  FIG. 14 . The diverting apparatus  210  of  FIG. 15 , which forms a wellbore  230 , comprises the same parts as those in  FIG. 14 ; therefore, like parts are designated with the same last two numbers. For example, the wellbores are  130  and  230 , the surfaces are  105  and  205 , the formations are  120  and  220 , and so on. 
     The diverting apparatus  210  of  FIG. 15  also comprises one or more pads  285  which are disposed on the outer diameter of the casing string  240 . Preferably, the pads  285  are located on the outer diameter of the casing string  240  on the side opposite the fluid deflector  275 . As the casing string  240  is drilled deeper into the formation  220 , the diverting apparatus  210  encounters increasing friction, making it increasingly difficult to drill the wellbore  230  into the formation  220 . The pads  285 , which are spaced vertically along the casing string  240 , serve to reduce friction encountered in the formation  220 . Furthermore, the pads  285  help to bias the casing string  240  outward at the desired angle in the preferred direction by keeping the casing string  240  from direct contact with the inner diameter of the wellbore  230 . The pads  285  maintain the cutting structure  250  heading outward, preventing it from falling back to vertical with respect to the axis of the upper portion of the casing string  240 . 
     The operation of the diverting apparatus  110  and  210  of  FIGS. 14 and 15  is similar, so they will be described in conjunction with one another. In operation, the diverting apparatus  110 ,  210  is drilled into the wellbore  130 ,  230  axially by downward force applied from the surface  105 ,  205 . The cutting apparatus  150 ,  250  drills into the formation  120 ,  220  due to the axial force. At the same time, pressurized fluid is introduced into the casing string  140 ,  240  from the surface  105 ,  205  to facilitate the downward movement of the diverting apparatus  110 ,  210  into the formation  120 ,  220 . The fluid forms a path for the diverting apparatus  110 ,  210  in the formation and prevents mud and rock from the formation  120 ,  220  from filling the inner diameter of the casing string  140 ,  240 . The fluid flows through the casing string  140 ,  240 , through the float sub  115 ,  215 , through the fluid deflector  175 ,  275 , and into an annular space  190 ,  290  between the outer diameter of the casing string  140 ,  240  and the inner diameter of the wellbore  130 ,  230 . Along the way, the fluid tends to flow into the area with the least obstruction. The fluid deflector  175 ,  275  urges the fluid outward into the formation  120 ,  220  at the angle in the preferred direction with respect to the vertical axis of the casing string  140 ,  240 , where no obstruction is present. In this way, fluid flow is selectively diverted out of a portion of the casing string  140 ,  240  to form a deflected path for the wellbore  130 ,  230 . The concentrated fluid flow into only one portion of the formation  120 ,  220  causes a profile  180 ,  280  in a portion of the formation  120 ,  220  to develop, forming a path through which the casing string  140 ,  240  may travel with less frictional resistance than the alternative paths through the formation  120 ,  220 . The lower portion  136 ,  236  of the casing string  140 ,  240  is thus biased at an angle off of the vertical axis of the upper portion  137 ,  237  casing string  140 ,  240 , in the general direction and at the general angle of the fluid deflector  175 ,  275 , so that the wellbore  130 ,  230  is angled in the preferential direction and the path of the wellbore  130 ,  230  is deflected accordingly. 
     Additionally, the fluid tends to flow outward at the angle off of the vertical axis at which the bend in the casing string  140 ,  240 , in this case the bend produced by the male and female threads  125 ,  225  and  135 ,  235 , biased the diverting apparatus  110 ,  210 . The lower portion  136 ,  236  of the casing string  140 ,  240  is thus urged at an angle in the preferential direction with respect to the upper portion  137 ,  237  of the casing string  140 ,  240  due to the fluid deflector  175 ,  275  and the threadable connections  125 ,  225  and  135 ,  235 . In the embodiment of  FIG. 15 , the pads  285  further urge the diverting apparatus  210  in the desired direction by reducing friction of the casing string  240  against the formation  220  along the way downward, as well as by propping the lower end of the casing string  240  with the cutting apparatus  250 , thus preventing the cutting apparatus  250  from falling back into the vertical angle with respect to the axis of the casing string  140 ,  240 . In this way, in either embodiment, the path of the casing string  140 ,  240  and, thus, of the wellbore  130 ,  230 , is deflected in the desired direction to avoid intersection with other wellbores. 
     After the casing string  140 ,  240  penetrates into the formation  120 ,  220  to form the wellbore  130 ,  230  at the desired angle at the desired depth, pressurized setting fluid such as cement may optionally be introduced into the wellbore  130 ,  230  from the surface  105 ,  205  through the casing string  140 ,  240 . The setting fluid flows through the casing string  140 ,  240 , through the float sub  115 ,  215 , through the fluid deflector  175 ,  275 , and then outward into the annular space  190 ,  290 . The float sub  115 ,  215  functions much like a check valve, in the open position allowing setting fluid to flow downward through the casing string  140 ,  240 , and in the closed position preventing setting fluid from flowing back upward through the casing string  140 ,  240  toward the surface  105 ,  205 . Specifically, the setting fluid, when flowing into the casing string  140 ,  240  from the surface  105 ,  205 , forces the ball  101 ,  201  downward within the float sub  115 ,  215  and out of the ball seat  102 ,  202 . The setting fluid can thus flow around the ball  101 ,  201  and through the float sub  115 ,  215  to flow into the annular space  190 ,  290 . The selling fluid solidifies within the annular space  190 ,  290  to secure the casing string  140 ,  240  within the wellbore  130 ,  230 . When setting fluid is no longer introduced into the casing string  140 ,  240  to force the ball  101 ,  201  out of the ball seat  102 ,  202 , the ball  101 ,  201  is again seated in the ball seat  102 ,  202  so that setting fluid cannot flow back upward within the casing string  140 ,  240  toward the surface  105 ,  205 . 
     After setting the casing string  140 ,  240 , the float sub  115 ,  215  and the landing seat  145 ,  245  may be drilled through by a cutting structure. Additional strings of casing (not shown) may then be hung off of the casing string  140 ,  240 . The additional casing strings are biased at an angle with respect to the vertical axis because the casing string  140 ,  240  leads the additional casing strings in its general direction and angle. The additional casing strings are set with setting fluid just as the casing string  140 ,  240  was set. 
       FIGS. 14 and 15  show a bend introduced into the casing  140 ,  240  at the threadable connection of male and female threads  125 ,  225  and  135 ,  235 . In the alternative, a bend in the casing  140 ,  240  could be integrally machined in the casing  140 ,  240 . It is also contemplated that embodiments of the present invention may include merely bending the casing  140 ,  240 . The bend in the casing  140 ,  240  would provide directional force for directionally drilling with the casing  140 ,  240 . 
       FIG. 55  shows a further alternate embodiment of a nudging operation of the present invention. In this embodiment, no bend is introduced into the casing as is shown in  FIGS. 14 and 15 , and no eccentric pads  285  are located on the outer diameter of the casing as shown in  FIG. 15 . Rather, in the embodiment of  FIG. 55 , one or more fluid deflectors (nozzles)  475  are located on one side of an earth removal member  350  operatively attached to a lower end of a casing  440  and are angled outward with respect to the vertical axis of the casing  440 , which may include a casing section or a casing string having a plurality of casing sections. As shown and described in relation to  FIGS. 14-15 , a fluid deflector  475  is formed through the casing  440  and the earth removal member  450 , which is preferably a cutting apparatus such as a drill bit. The earth removal member  450  may be a bi-center bit, expandable bit, drillable cutting structure, or the like, depending upon the application. The fluid deflector  475  is biased and angled in the direction in which it is desired to divert the wellbore, or in the preferential direction of the wellbore. The fluid deflector  475  is substantially the same as the fluid deflectors  175  and  275  of  FIGS. 14 and 15 , respectively. As in the embodiments shown in  FIGS. 14 and 15 , any number of fluid deflectors  475  may be utilized in the present invention. 
     As in the embodiments shown in  FIGS. 14 and 15 , a float sub  415  and landing seat  445  for a survey tool (not shown) may be located within the diverting apparatus  410 . Because the float sub  415  is substantially the same as the float subs  115 ,  215  shown and described with respect to  FIGS. 14 and 15 , the above description of the float subs  115 ,  215  of  FIGS. 14 and 15  and their operation applies equally to the float sub  415  of  FIG. 55 . Similarly, because the landing seats  45 ,  145 , and  245  of  FIGS. 13 ,  14 , and  15 , respectively, are substantially the same as the landing seat  445 , the above description of the landing seats  45 ,  145 , and  245  and their operation applies equally to the embodiment of  FIG. 55 . 
     In a preferred embodiment, the diverting apparatus  410  includes a plurality of fluid deflectors or nozzles  475  grouped together on one side of the cutting apparatus  450 .  FIG. 57  illustrates a particularly preferred embodiment, which includes three fluid deflectors or nozzles  475 A,  475 B, and  475 C through the casing  440  and cutting apparatus  450  for preferentially directing the fluid flow into the formation. The fluid deflectors  475 A, B, and C may be pointed straight down, where the axes of the fluid deflector  475 A, B, and C are parallel to the axis of the cutting apparatus  450 . Alternately, the fluid deflectors  475 A, B, and C may be angled radially outward from the cutting apparatus  450 , so that the axes of the fluid deflectors  475 A, B, and C are at an angle with respect to the axis of the cutting apparatus  450 . In one embodiment, one or more of the fluid deflectors  475 A, B, and C may be angled, while the remainder of the fluid deflectors  475 A, B, and C may be straight. In a preferred embodiment, the vertical axes of the fluid deflectors  475  A, B, and C are angled approximately 30 degrees radially outward from the vertical axis of the cutting apparatus  450 . 
     In operation, to form a deflected wellbore, the diverting apparatus  410  may be alternately jetted by flowing fluid through the casing  440  and into the fluid deflector  475  while simultaneously lowering the casing  440  into the formation, and rotated by rotating the entire casing  440  within the formation. During jetting of the fluid through the deflector  475 , fluid through the deflector  475  forms a path for the diverting apparatus  410  in the formation in the same way as described above in relation to the fluid deflectors  175 ,  275  shown and described in relation to  FIGS. 14 and 15 . Namely, the fluid flows into the area of the formation having the least obstruction, and the angled orientation of the fluid deflector  475  urges the fluid outward from the casing  440  into the formation at the angle in the preferred direction with respect to the vertical axis of the casing  440 . Concentrated fluid flow in a portion of the formation causes a profile in a corresponding portion of the formation to form so that the casing  440  travels through the path of least resistance to form a deflected wellbore path. 
     After the casing  440  has reached the desired depth within the formation, a physically alterable bonding material such as cement may be flowed through the casing  440  to set the casing  440  within the wellbore, in the same manner as described in relation to setting the casing  140 ,  240  of  FIGS. 14 and 15 , using the float sub  415 . After possibly retrieving the survey tool which may optionally be located within the landing seat  445 , if the float sub  415 , landing seat  445 , and cutting apparatus  450  are drillable, the float sub  415 , landing seat  445 , and cutting apparatus  450  may each be drilled through by a subsequent cutting structure, e.g., a cutting structure located on a subsequent drill string or subsequent casing. If the components are drilled through by a subsequent cutting apparatus on a subsequent casing, the additional casing may then be hung off the casing  440  (preferably at a lower end of the casing  440 ) and possibly set with a physically alterable drilling material within the wellbore. This process may be repeated as desired to drill and case the wellbore to a total depth. The additional casing strings are biased at an angle with respect to the vertical axis of the casing  440  because of the casing  440  deflection. 
     In a preferred operation of the embodiment shown in  FIG. 55 , the casing  440  may be alternately jetted and/or rotated to form a wellbore within the formation. To form a deviated wellbore, the rotation of the casing  440  is halted, and a surveying operation is performed using the survey tool (not shown) to determine the location of the one or more fluid deflectors  475  within the wellbore. Stoking may also be utilized to keep track of the location of the fluid deflector(s)  475 , the method of which is described in relation to  FIG. 31  (see below). 
     Once the location of the fluid deflector(s)  475  within the wellbore is determined, the casing  440  is rotated if necessary to aim the fluid deflector(s)  475  in the desired direction in which to deflect the casing  440 . Fluid is then flowed through the casing  440  and the fluid deflector(s)  475  to form a profile (also termed a “cavity”) in the formation. Then, the casing  440  may continue to be jetted into the formation. When desired, the casing  440  is rotated, forcing the casing  440  to follow the cavity in the formation. The locating and aiming of the fluid deflector(s)  475 , flowing of fluid through the fluid deflector(s)  475 , and further jetting and/or rotating the casing  440  into the formation may be repeated as desired to cause the casing  440  to deflect the wellbore in the desired direction within the formation. 
     A further alternate embodiment of the present invention involves accomplishing a nudging operation to directionally drill the casing  440  into the formation and expanding the casing  440  in a single run of the casing  440  into the formation, as shown in  FIGS. 56A and 56B . Additionally, cementing of the casing  440  into the formation may optionally be performed in the same run of the casing  440  into the formation.  FIGS. 56A-B  show the diverting apparatus  410 , including casing  440 , the earth removal member or cutting apparatus  450 , the one or more fluid deflectors  475  (which may be a plurality of fluid deflectors arranged as shown and described in relation to  FIG. 57 ), and the landing seat  445  of  FIG. 55 . 
     Additional components of the embodiment of  FIGS. 56A and 56B  include an expansion tool  442  capable of radially expanding the casing  440 , preferably an expansion cone  442 ; a latching dart  486 ; and a dart seat  482 . The expansion cone  442  may have a larger outer diameter at its upper end than at its lower end, and preferably slopes radially outward from the upper end to the lower end. The expansion cone  442  may be mechanically and/or hydraulically actuated. The latching dart  486  and dart seat  482  are used in a cementing operation. 
     In operation, the diverting apparatus  410  is lowered into the wellbore with the expansion cone  442  located therein by alternately jetting and/or rotating the casing  440 , most preferably by nudging the casing  440  according to the preferred method described in relation to  FIG. 55 . Next, a running tool  425  is introduced into the casing  440 . A physically alterable bonding material, preferably cement, is pumped through the running tool  425 , preferably an inner string. Cement is flowed from the surface into the casing  440 , out the fluid deflector(s)  475 , and up through the annulus between the casing  440  and the wellbore. When the desired amount of cement has been pumped, the dart  486  is introduced into the inner string  425 . The dart  486  lands and seals on the dart seat  482 . The dart  486  stops flow from exiting past the dart seat, thus forming a fluid-tight seal. Pressure applied through the inner string  425  may help urge the expansion cone  442  up to expand the casing  440 . In addition to or in lieu of the pressure through the inner string  425 , mechanical pulling on the inner string  425  helps urge the expansion cone  442  up. 
     Rather than using the latching dart  486 , a float valve  415  as shown and described in relation to  FIG. 55  may be utilized to prevent back flow of cement. The latching dart  486  is ultimately secured onto the dart seat  482 , preferably by a latching mechanism. 
     The running tool  425  may be any type of retrieval tool. Preferably, the retrieval of the expansion cone  442  involves threadedly engaging a longitudinal bore through the expansion cone  442  with a lower end of the running tool  425 . The running tool  425  is then mechanically pulled up to the surface through the casing  440 , taking the attached expansion cone  442  with it. Alternately, the expansion cone  442  may be moved upward due to pumping fluid, down through the casing  440  to push the expansion cone  442  upward due to hydraulic pressure, or by a combination of mechanical and fluid actuation of the expansion cone  442 . As the expansion cone  442  moves upward relative to the casing  440 , the expansion cone  442  pushes against the interior surface of the casing  440 , thereby radially expanding the casing  440  as the expansion cone  442  travels upwardly toward the surface. Thus, the casing  440  is expanded to a larger internal diameter along its length as the expansion cone  442  is retrieved to the surface. 
     Preferably, expansion of the casing  440  is performed prior to the cement curing to set the casing  440  within the wellbore, so that expansion of the casing  440  squeezes the cement into remaining voids in the surrounding formation, possibly resulting in a better seal and stronger cementing of the casing  440  in the formation. Although the above operation was described in relation to cementing the casing  440  within the wellbore, expansion of the casing  440  by the expansion cone  442  in the method described may also be performed when the casing  440  is set within the wellbore in a manner other than by cement. 
     As mentioned in relation to the embodiment of  FIG. 55 , the cutting apparatus  450  may be drilled through by a subsequent cutting structure (possibly attached to a subsequent casing) or may be retrieved from the wellbore, depending on the type of cutting structure  450  utilized (e.g., expandable, drillable, or bi-center bit). Regardless of whether the cutting structure  450  is retrievable or drillable, the subsequent casing may be lowered through the casing  440  and drilled to a further depth within the formation. The subsequent casing may optionally be cemented within the wellbore. The process may be repeated with additional casing strings. 
       FIG. 16  shows a diverting apparatus  310  drilled into a formation  320  to form a wellbore  330 . The diverting apparatus  310  includes an upper casing  340 , as well as a lower casing  341 . The upper and lower casings  340  and  341  are inserted into the formation  320  as a unit. The lower casing  341  has a first cutting apparatus  350  attached to its lower end. At least one nozzle  355  runs through the lower end of the lower casing  341  as well as through the first cutting apparatus  350 . The at least one nozzle  355  allows for fluid circulation between the casings  340 ,  341  and the wellbore  330 . 
     The diverting apparatus  310  also includes an elongated coupling  391 , which is a collar used to connect the upper and lower casing strings  340  and  341  to one another. An upper portion of the elongated coupling  391  is connected to a lower portion of the upper casing  340  by a threadable connection  342 . Similarly, a lower portion of the elongated coupling  391  is attached to an upper portion of the lower casing  341  by a threadable connection  343 . The elongated coupling  391  has a second cutting apparatus  395  located on its outermost portion. In the alternative, only one casing (not shown) may have a second cutting apparatus  395  disposed thereon, which is not necessarily attached by a threadable connection. The outer diameter of the second cutting apparatus  395 /elongated coupling  391  is larger than the outer diameter of the first cutting apparatus  350 . The second cutting apparatus  395  extends along a substantial portion of the length of the elongated coupling  391 , and even along the lower portion of the elongated coupling  391 , so that the cutting apparatus  395  cuts into the formation  320  as the diverting apparatus  310  is forced progressively downward to form the wellbore  330 . The second cutting apparatus  395  possesses hole-opening blades which increase the inner diameter of the upper portion of the wellbore  330 . 
     In operation, the diverting apparatus  310  is urged into the formation  320  by downward axial force applied from a surface  305  of the wellbore  330 . The elongated coupling  391  of the diverting apparatus  310  allows the two casings  340  and  341  to be threaded together at the well site, so that the diverting apparatus  310  does not have to be pre-manufactured on the casing  340  or  341 . In the alternative, the second cutting apparatus  395  may be pre-manufactured on the casing string (not shown). As described above in relation to the other embodiments, pressurized fluid is introduced into the diverting apparatus  310  through the inner diameter of the upper casing  340  as the casing  340 ,  341  penetrates into the formation  320  to form the wellbore  330 , and then the fluid flows into the lower casing  341 , through the at least one nozzle  355 , up through a second annular space  389  between an inner diameter of the wellbore  330  and an outer diameter of the lower casing  341 , up through a first annular space  390  between the inner diameter of the wellbore  330  and an outer diameter of the upper casing  340 , and to the surface  305  of the wellbore  330 . 
     While the diverting apparatus  310  is moving axially downward through the formation  320  and the fluid is circulating, the first cutting apparatus  350  cuts into the formation  320  to form a lower portion of the wellbore  330  approximately equal to its diameter. Likewise, the second cutting apparatus  395  at the same time cuts into the formation  320  to form an upper portion of the wellbore  330  approximately equal to its diameter. The outer diameter of the upper portion of the wellbore  330  is larger than the outer diameter of the lower portion of the wellbore  330  because of the difference in diameter between the first cutting apparatus  350  and the second cutting apparatus  395 . 
     Because of the difference in diameters between the upper and lower portions of the wellbore  330 , the first annular space  390  between the outer diameter of the upper casing  340  and the inner diameter of the upper portion of the wellbore  330  is larger than the second annular space  389  between the outer diameter of the lower casing  341  and the inner diameter of the lower portion of the wellbore  330 . The axial movement is halted when the diverting apparatus  310  reaches its desired depth in the wellbore  330 . 
     The first annular space  390  at the top of the wellbore  330  is larger than the second annular space  389  at the bottom of the wellbore  330  as a result of the enlarged diameter second cutting apparatus  395 , so that a larger diametral clearance exists at the upper portion of the wellbore  330  than at the lower portion of the wellbore  330 . The larger diametral clearance allows gravity to cause the casing to buckle in a direction. The direction in which gravity causes the casing to buckle is illustrated by the arrows disposed within the first annular space  390 . Fulcrum force is illustrated by the arrows perpendicular to the axis of the casing  340 ,  341  and adjacent to the second cutting structure  395 . A force in the opposite direction caused by formation  320  frictional resistance is depicted by the arrow perpendicular to the axis of the first cutting apparatus  350 . The effect of the forces shown by the arrows in  FIG. 16  is that the upper casing  340  moves laterally through the first annular space  390  while staying essentially anchored at the lower portion of the lower casing  341  by the second annular space  389 , so that the diverting apparatus  310  angles in the preferred direction. The second cutting apparatus  395 , or the additional dressing on the outer diameter of the casing  340  and/or  341 , thus creates a larger cavity in the upper portion of the wellbore  330  than in the lower portion of the wellbore  330 , which facilitates lateral movement of the casing  340  in the preferred direction to create a deflected path for the wellbore  330 . 
     Again, a survey tool (not shown) placed in a landing seat (not shown) as described above may be used to determine whether the diverting apparatus  310  is bent in the desired direction at the desired angle. Once the diverting apparatus  310  is deviated into the desired angle, the first and second casings  340  and  341  are cemented into place by a setting operation as described above. All of the components disposed within the inner diameter of the casing  340  are preferably made of drillable material so that they may be drilled through after the setting operation so that the inner diameter of the casing  340  is essentially hollow for subsequent wellbore operations. Subsequent casings (not shown) are then run into the wellbore  330  and hung from the existing lower casing  341 . The subsequent casings are biased in the desired direction at the desired angle because they essentially conform to the angle set by the original casings  340  and  341 . 
       FIG. 17  shows an alternative embodiment of a diverting apparatus of the present invention. The diverting apparatus  1310  is substantially similar to the diverting apparatus  310  shown and described in relation to  FIG. 16 ; as such, like parts will not be described again herein. The embodiment shown in  FIG. 17  is different from the embodiment shown in  FIG. 16  because instead of the concentric stabilizer acting as the second cutting apparatus, an eccentric stabilizer  1395  disposed asymmetrically on one side of the outer diameter of the casing  1340 ,  1341  adds additional directional force to the diverting apparatus  1310 . In the depiction of the diverting apparatus  1310  shown in  FIG. 17 , the stabilizer  1395 , which is preferably a 1-bladed actuable kick-pad, causes the upper portion of the casing  1340  to angle in the opposite direction from the eccentric stabilizer  1395 . As an additional directional force acting in the same direction as the stabilizer  1395  is biasing the casing  1340 ,  1341 , a fluid deflector  1355 , or a perforation in the cutting apparatus  1350  angled in a direction with respect to vertical, may also be utilized to further deflect the path of the wellbore  1330  in a preferential direction at an angle with respect to the vertical axis of the casing. 
     In the operation of the embodiments of  FIGS. 16-17 , a two-step process may be utilized. First, oriented jetting through the one or more fluid deflectors (bit nozzles)  1355  may be accomplished to establish an initial inclination and direction of the casing. Then, the casing  340  and  341 ,  1340  and  1341  may be rotary drilled further into the formation using the second cutting apparatus  395 ,  1395  to build the angle. To rotary drill, the entire casing  340  and  341 ,  1340  and  1341  is rotated while lowering the casing into the formation  320 ,  1320 . By using this two-step process, the more efficient rotary drilling method may be utilized to build the angle of the wellbore  330 ,  1330 . 
     Finally,  FIGS. 18-20  illustrate an apparatus and method which may be utilized with a diverting apparatus  510  to drill through the inner diameter of the diverting apparatus  510  and remove obstructions so that additional casing strings (not shown) may be hung from the diverting apparatus  510  after the initial diversion. The apparatus and method of  FIGS. 18-20  may be used with any of the above embodiments to remove obstructing portions of the diverting apparatus residing within the inner diameter of the casing string after the casing string has been set within the wellbore. Referring to  FIG. 18 , the diverting apparatus  510  includes a casing string  540  with a second cutting apparatus  595  disposed on its outer diameter. The casing string  540  is inserted into a formation  520  to form a wellbore  530 . The inner diameter of the casing string  540  has a drillable member  521  attached thereto which is connected to a drilling apparatus  522  through releasable connections  506 . The releasable connections  506 , which are preferably shearable connections, are used to fix the diverting apparatus  510  relative to the drilling apparatus  522  torsionally and axially. 
     The drilling apparatus  522  includes a drill string  523  with a first cutting apparatus  550  connected to its lower end. The first cutting apparatus  550  is smaller in diameter than the second cutting apparatus  595 , so that the second cutting apparatus  595  possesses hole-opening blades which enlarge the inner diameter of the upper portion of the wellbore  530 . The first cutting apparatus  550  has a cutting structure  551  attached to its lower end, at least one side parallel to a wellbore  530 , and its backside  526  at an angle from the wellbore  530 . The first cutting apparatus  550  has at least one nozzle  555  which allows fluid to flow into and in from a formation  520 . Threads  501  are preferably located on an upper end of the drill string  523  on its inner diameter. 
     The operation of the diverting apparatus  510  and the drilling apparatus  522  is shown in  FIGS. 18-20 .  FIG. 18  illustrates the diverting/drilling apparatus  510 / 522  during run-in of the casing string  540 . The diverting apparatus  510  with the drilling apparatus  522  attached thereto is pushed downward axially into the formation  520  to form the wellbore  530 . The diverting/drilling apparatus  510 / 522  may also be rotated from a surface  505  of the wellbore  530  if desired to drill through the formation  520 . The first cutting apparatus  550  drills into the formation  520  due to the pressure placed on the casing string  540 , which translates to the drilling apparatus  522 . During the run-in of the casing string  540 , the first cutting apparatus  550  on the drilling apparatus  522  initially forms a portion of the wellbore  530  of a first diameter. The second cutting apparatus  595  enlarges the diameter of the wellbore  530  in the portion of the wellbore  530  that it is forced into, as the second cutting apparatus  595  is larger in diameter than the first cutting apparatus  550 . Thus, a first annular space  590  between the outer diameter of the casing string  540  and the inner diameter of the wellbore  530  is larger than a second annular space  589  between the outer diameter of the drill string  523  and the inner diameter of the wellbore  530 . The second cutting apparatus  595 , or the additional dressing on the outer diameter of the casing string  540 , thus creates a larger cavity in the upper portion of the wellbore  530  than in the lower portion of the wellbore  530 , which facilitates lateral movement of the casing string  540  in the preferred direction to create a deflected path for the wellbore  530 . Pressurized fluid is introduced into the casing string  540  while the casing string  540  penetrates into the formation  520  to form the wellbore  530  to flush mud and other substances out of the casing string  540  through the at least one nozzle  555  in the cutting apparatus  550 , outside the drill string  523  and the casing string  540 , and up to the surface  505 . 
     After the diverting/drilling apparatus  510 / 522  is drilled into the desired depth in the wellbore  530  at which to divert and set the casing string  540 , a working string  503  or some other retrieving tool is lowered into the inner diameter of the casing string  540  (the working string  503  is shown in  FIG. 19 ). The working string  503  retrieves the drill string  523  using a pulling tool profile on its lower end, preferably male threads  502  on the working string  503  which threadedly engage female threads  501  of the drill string  523 . 
       FIG. 19  illustrates the next step in the operation of the diverting/drilling apparatus  510 / 522 . The working string  503  is pulled upward axially from the surface  505  to release the releasable connection  506 . The releasable connection  506  is preferably sheared off. As a consequence of the release, the drill string  523  is moveable axially and rotationally relative to the diverting apparatus  510 . The drilling apparatus  522  is then pulled upward and rotated through the wellbore  530  by the working string  503 . The cutting structure  551  on the backside  526  of the first cutting apparatus  550  contacts the lower end of the drillable member  521  and the portion of the releasable connection  506  remaining on the drillable member  521 . 
     As seen in  FIG. 20 , the cutting structure  551  drills completely through the drillable member  521  and the remaining portion of the releasable connection  506  so that the drillable member  521  and releasable connection  506  are essentially destroyed. The inner diameter of the casing string  540  is therefore left effectively unobstructed so that wellbore operations may be performed or additional casing strings (not shown) may eventually be hung from the casing string  540 . The drilling apparatus  522  is then removed from the wellbore  530  by the working string  503 . 
     Finally, the casing string  540  is bent from the surface  505  to a side at an angle. Because of the larger first annular space  590  at the upper portion of the casing string  540 , the casing string  540  is fixed at its lower end but moves through the first annular space  590  at its upper portion so that the casing string  540  is biased at an angle. The additional casing strings may then be hung off of the casing string  540  at the angle at which the casing string  540  is biased, allowing the wellbore  530  to deviate in the desired direction at the desired angle. 
     In the embodiments shown in  FIGS. 13-20 , the float sub may include, but is not limited to, the following: a check valve, poppet valve, flapper valve, or any other type of one-way valve. Drillable material utilized to form the float sub may include, but is not limited to, one or more of the following: aluminum, plastic, metal, cement, or combinations thereof. 
     Furthermore, in any of the embodiments shown in  FIGS. 13-20 , the cutting structure may be a drillable drill bit or an expandable bit latched into the casing. For an example of an expandable bit suitable for use in the present invention, refer to U.S. Patent Application Publication No. 2003/111267 or U.S. Patent Application Publication No. 2003/183424, each which is incorporated by reference herein in its entirety. 
     The diverting apparatus of the present invention and methods for their use allow effective diversion of a wellbore in a direction by deflecting a string of casing inserted into the wellbore. The apparatus and methods are simple to build and permit the wellbore diversion to be accomplished while drilling with casing in a subterranean wellbore. Accordingly, the apparatus and methods of the present invention aid in preventing the unwanted intersection of valuable subterranean wellbores. 
     The diverting apparatus of  FIGS. 13-20  used for nudging may be utilized as the outer casing  185  shown in  FIG. 1 , while the inner casing  195  may be any of the embodiments depicted in  FIGS. 1-12 . In this manner, referring to  FIG. 1 , the system  100  is jetted and/or rotated to lower the outer casing  185  into the earth formation  112  at the desired depth to form a deviated wellbore. Next, the releasable connection between the inner casing  195  and the outer casing  185  is released, and the inner casing  195  is jetted and/or rotated, and the drilling system  157  may also be utilized to drill the inner casing  195  to the desired depth within the formation  112  while continuing to bias the direction and angle of the wellbore. The drilling system may include any of the embodiments shown in  FIGS. 1-12 . 
     In the most preferable embodiment of  FIGS. 13-20 , the casing is alternately rotated and/or lowered or jetted into the formation. The rotation and jetting alternation aids in achieving the desired trajectory of the wellbore. 
     In conventional drilling operations, hydraulic horsepower is delivered to the cutting structure through one or more very restrictive orifices or nozzles (commonly termed “bit nozzles”) located in the cutting structure. The nozzles are usually located in the body of the cutting structure proximate to the bottom of the wellbore. The function of the nozzles is primarily to puncture the earth formation with “jet” impacts to facilitate formation of the wellbore, then to carry the cuttings up to the surface through the annulus between the wellbore and the casing. Additional functions of nozzles and the fluid flow therethrough include cleaning the cutting structure, cooling the bit cutters, and cleaning the bottom of the wellbore. For the nozzles to perform this function, the horsepower of the fluid flowing through the nozzles must be high during jetting. Because of the high horsepower of the hydraulic fluid traveling through the nozzles while jetting, the nozzles are subjected to extremely high erosion caused by pressure drop of the drilling fluid across the nozzles (e.g., from 500 to 3000 psi) and high velocity of the fluid through the nozzles (e.g., from 200 to 800 ft/s). 
     The necessary high flow rate of fluid through the nozzles to perform an adequate jetting operation requires that the nozzles be made of materials which allow the nozzles to be sufficiently hard and tough to withstand the erosion due to the fluid through the nozzles. Typically, therefore, a hard and tough material such as tungsten carbide and/or ceramic is used to jet into the formation with a drill string in conventional drilling operations, as nozzles constructed from one or more of these materials may endure for thousands of hours without suffering fatal damage from erosion. Drilling with casing operations, however, such as those that are shown in  FIGS. 1-22 , may require that the nozzles be drillable, and the current ceramic or tungsten carbide nozzles used for jetting in the drill string are not drillable. 
     Drilling with casing operations may require the same fluid intensity while jetting and/or rotating the casing as is required when circulating drilling fluid in the drill string while drilling. The amount of time that the fluid intensity must be maintained during drilling may be less for drilling with casing operations than in traditional drilling operations, however. 
     In the embodiments of the present invention shown in  FIGS. 1-20 , an expandable cutting structure or a drillable cutting structure may be utilized. An alternate embodiment may include a drillable cutting structure, possible including drillable nozzles.  FIG. 21  shows a process for drilling through a drillable cutting structure  1615  such as a drill bit or drill shoe operatively attached to a casing  1610 . The drillable cutting structure  1615  has drillable nozzles  1616  therein. The casing  1610  is lowered into the earth formation  1605  to form a wellbore  1630  by rotating the casing  1610  and/or by jetting the casing  1610 . After the casing  1610  is lowered and/or drilled into the earth formation  1605  to the desired depth, in one embodiment the casing  1610  may be set therein using a physically alterable bonding material such as cement (not shown). 
     As shown in  FIG. 21 , a casing  1620  is lowered into the inner diameter of the casing  1610  while introducing fluid F through the inner diameter of the casing  1620 , out through nozzles  1626  in a cutting structure  1625  in the casing  1620 , and up to the surface. The cutting structure  1625  may, but does not necessarily have to be, drillable. The cutting structure  1625  may in the alternative be expandable and retrievable from the wellbore  1630 . 
       FIG. 22  illustrates the next step in an embodiment of the method for drilling through a cutting structure on a casing. The casing  1620  is lowered and/or rotated through the casing  1610  to drill through at least a portion of the cutting structure  1615 . The nozzles  1616  are preferably also drillable, as described below. 
       FIG. 22  shows the casing  1620  drilling to a further depth within the formation  1605 . After the casing  1620  is lowered to the desired depth within the formation  1605 , the casing  1620  may be expanded in one embodiment. If desired, the casing  1620  may also be set therein using the physically alterable bonding material. Subsequently, the cutting structure  1625  may be left in the wellbore  1630  or may be drilled through by an additional casing (not shown) or by a drill string or other cutting device. 
     The present invention provides drillable nozzles for use while drilling with casing. For the cutting structure  1615  to be drillable, the base material and the nozzle(s) of the cutting structure  1615  must be soft enough to allow subsequent casing  1620  to drill therethrough. However, a nozzle constructed of a sufficiently soft material used in a drilling with casing application may only last a few hours under intense fluid erosion due to jetting. While enlarging the nozzle diameter to reduce velocity of the fluid through the nozzle aids in increasing nozzle longevity, this design remains problematic because the velocity of the fluid through the nozzle(s) may be so decreased that the casing no longer sufficiently drills through the formation during the jetting process. 
       FIGS. 23A-23B ,  24 A-B, and  25 - 29  show embodiments of the present invention of a drillable nozzle, of which one or more may be used in any of the embodiments in  FIGS. 1-22 . The nozzles shown in  FIGS. 23A-23B ,  24 A-B, and  25 - 29  are insertable into the cutting structures of  FIGS. 1-22  to provide a fluid path from the inner diameter of the casing into the wellbore. The drillable nozzle breaks into portions, preferably fragments or “cuttings”, to be flowed to the surface using drilling fluid through the casing (not shown) which is used to drill through the drillable nozzle. The drillable nozzles of  FIGS. 23A-23B ,  24 A-B, and  25 - 29  are drillable while remaining sufficiently devoid of erosive deconstruction to allow functional jetting through the nozzles with drilling fluid or any other fluid introduced into the nozzles. 
     In the embodiment shown in  FIGS. 23A and 23B , the drillable nozzle  1700  is constructed of a hard, brittle, and wear-resistant material. Exemplary base materials which may be utilized to form the drillable nozzle  1700  include, but are not limited to, tungsten carbide, ceramic, and polycrystalline diamond (PDC).  FIG. 23B  shows a first end  1751  of the nozzle  1700 , through which fluid F is flowable during a drilling with casing operation. While drilling with the casing attached to the cutting structure having at least one drillable nozzle  1700  therein, fluid F is flowable through the casing, into the first end  1751 , through a bore  1761  disposed within the nozzle  1700 , out through a second end  1741  of the nozzle  1700  (shown in  FIG. 23A ), then up through an annulus between the casing and the wellbore (or another casing disposed therearound) to the surface. 
     The drillable nozzle  1700  has one or more stressed portions therein, specifically shown as one or more stressed notches  1710  in  FIGS. 23A-B . Preferably, the stressed notches  1710  are disposed within the outer diameter of the nozzle  1700  and are at least partially subflushed to the surface of the nozzle  1700 . The stressed notches  1710  preferably extend the length of the nozzle  1700  coaxially with the bore  1761  of the nozzle  1700 ; however, it is contemplated that the stressed notches  1710  may extend only a portion of the length of the nozzle  1700 . The stressed notches  1710  provide a stress point to cause the nozzle  1700  to break into portions or fragments when drilled through with a subsequent casing, drill string, or other cutting device. While not a requirement for use in the present invention, a preferred embodiment provides that the notches  1710  are spaced substantially equidistant from one another along the outer diameter of the nozzle  1700 . The notches  1710  are preferably relatively narrow cuts throughout the length of the nozzle  1700 . 
     An o-ring groove  1705  may exist within the outer diameter of the body of the nozzle  1700  around its circumference for disposing an o-ring (not shown) therein to seal the nozzle  1700  within a body of the tool in which the nozzle  1700  is disposed, such as a cutting tool (not shown). In one embodiment, a filler material  1715 , preferably an extrudable material such as epoxy or vulcanized rubber, is disposed at least partially within the notches  1710  when the notches  1710  extend the length of the nozzle  1700  so that the o-ring may seal in the o-ring groove  1705 . 
       FIGS. 24A and 24B  illustrate another embodiment of a drillable nozzle  1800 . A first end  1851  of the nozzle  1800  is shown in  FIG. 24B , while a second end  1841  of the nozzle  1800  is depicted in  FIG. 24A . When the drillable nozzle  1800  is disposed in a cutting tool (not shown) operatively connected to a lower end of a casing (not shown), fluid F flows through the casing, into the first end  1851  of the nozzle  1800 , through a bore  1861  within the nozzle  1800 , out through the second end  1841 , then up through the annulus between the casing and the wellbore or between the casing and another casing disposed within the wellbore therearound. 
     The embodiment shown in  FIGS. 24A and 24B  is substantially the same as the embodiment shown in  FIGS. 23A and 23B , except for the following aspects. The stressed notches  1810  extend only through a portion of the nozzle  1800 , coaxial with the bore  1861 . The notches  1810 , which are again at least partially subflushed to the surface of the nozzle  1800 , are interrupted along at least a portion of the outer diameter of the nozzle  1800 . Preferably, the portion of the outer diameter of the nozzle  1800  over which the notches  1810  are interrupted is at least the at o-ring groove  1805 , negating the need to fill the notches  1810  with filler material  1715  as in  FIGS. 23A-B . An additional difference between the nozzle  1700  and the nozzle  1800  is that the notches  1810  are preferably substantially wider than the notches  1710 . 
     In the embodiments of  FIGS. 23A-B  and  24 A-B, the nozzles  1700  and  1800  provide longevity to and allow high flow rates of fluid to pass through the cutting structure operatively connected to the casing. At the same time, when the nozzles  1700  and  1800  are drilled through by a subsequent cutting structure placed on a subsequent casing or drill string, the broken nozzle portions may be circulated to the surface through an annulus between the subsequent casing or drill string and the wellbore. 
       FIGS. 25-28  show nozzle assemblies which may be utilized in a drillable cutting structure operatively attached to casing.  FIGS. 25 and 26  show extended flow tubes  1910 ,  2010  having a minimum thickness and a substantially uniform inner diameter or bore along each of their lengths. The flow tubes  1910 ,  2010  each represent a portion of the nozzle assemblies  1900 ,  2000 .  FIGS. 27 and 28  show relatively thin profiled flow tubes  2180 ,  2280 , each of which represent a portion of the nozzle assemblies  2100 ,  2200 . 
     In the embodiment of the present invention illustrated in  FIG. 25 , the nozzle assembly  1900  includes a flow tube  1910  disposed within a nozzle retainer  1920 . The flow tube  1910  is substantially tubular-shaped with a longitudinal bore therethrough. Additionally, the flow tube  1910 , which is preferably constructed of a relatively hard material such as ceramic, tungsten carbide, or PDC, is relatively thin (i.e., has a low thickness, as measured from an outer diameter to an inner diameter of the flow tube  1910 ) to facilitate drillability of the flow tube  1910  when a cutting structure, such as an earth removal member attached to a casing or a drill string, is drilled through the flow tube  1910 . 
     The flow tube  1910  has a substantially uniform inner diameter bore along its length to form a substantially straight bore through the flow tube  1910 . The substantially straight bore of the flow tube  1910  maintains a minimal thickness along the length of the flow tube  1910 , thus enhancing drillability of the flow tube  1910  with a subsequent cutting structure, as any profile of the flow tube  1910  other than a straight bore therethrough would require an increase in material thickness perpendicular to the axis of the flow tube  1910 . The material thickness perpendicular to the axis of the flow tube  1910  is presented to the subsequent cutting structure for drilling therethrough. Also, the internal profile of the flow tube  1910  formed by the substantially straight bore therethrough potentially decreases erosion of one or more portions of the nozzle  1900  because the fluid does not have to change direction due to obstructions within the bore when flowing through the nozzle  1900 . 
     The nozzle retainer  1920 , which is preferably constructed of a relatively soft, drillable material such as copper or plastic, retains the flow tube  1910  therein. The flow tube  1910  is preferably mounted within the nozzle retainer  1920 , which is a tubular-shaped body with a longitudinal bore therethrough. The nozzle retainer  1920  may include an installation and removal feature, such as slots  1940  shown in  FIG. 25  in an exit side face  1970  of the nozzle retainer  1920 . The slots  1940  facilitate installation and removal of the nozzle assembly  1900  from a tool body  1925 . 
     An integral feature of the nozzle assembly  1900  is the extended length of the flow tube  1910 . Due to the extended length of the flow tube  1910 , the flow tube  1910  may be positioned as desired within the nozzle retainer  1920  by moving the flow tube  1910  up or down (right or left as shown in  FIG. 25 ) within the nozzle retainer  1920 . Moving the flow tube  1910  up or down coaxial with the retainer  1920  allows entry and exit points of the fluid (shown in  FIG. 25 , as the fluid flow moves left to right in the depicted assembly  1900 ) to be positioned as required either closer to or away from areas which may be susceptible to fluid erosion as a result of high velocity of the fluid and turbulence caused by the high flow rate of the fluid while the fluid is entering or exiting the flow tube  1910 . Additionally, moving the flow tube  1910  down relative to the tool body  1925  would allow the exit point of the fluid from the nozzle assembly  1900  to be positioned closer to the formation than a typical nozzle design, thus improving effectiveness of the jetting through the nozzle assembly  1900  to remove portions of the formation by enabling increased control of exit standoff  1960  and entry standoff  1950 . Exit standoff  1960  is the distance of fluid flow through the flow tube  1910  measured from between the exit side face of the tool body  1925  and the exit point of the fluid from the flow tube  1910 , while entry standoff  1950  is the distance of fluid flow within the flow tube  1910  measured from between the entry side face of the tool body  1925  and the entry point of the fluid into the flow tube  1910 . 
     The nozzle retainer  1920  is preferably constructed of a relatively soft, drillable material such as copper or plastic. The material that the retainer  1920  is made from is softer than the material of the flow tube  1910 . Also, the material of the flow tube  1910  is more resistant to corrosion than the material of the retainer  1920 . The internal bore of the retainer  1920  is profiled to produce a controlled fit over the outer diameter of the flow tube  1910 , with a gap  1947  left between the flow tube  1910  and the retainer  1920  which is preferably substantially filled with a suitable adhesive  1945  for retaining the flow tube  1910  in the desired position within the retainer  1920 . 
     The retainer  1920  is seated within a nozzle profile  1965  in a tool body  1925 . The tool is preferably an earth removal member for cutting into an earth formation, and even more preferably a cutting structure such as a drill bit or drill shoe. The tool body  1925  is preferably constructed of a relatively soft, drillable material such as copper or plastic. An outer surface of the retainer  1920  has a seal groove  1907  having a seal  1905  therein for preventing fluid flow across the interface of the outer surface of the retainer  1920  and the nozzle profile  1965  of the tool body  1925 . An external thread  1915  secures the nozzle assembly  1900  within the tool body  1925 . 
     Advantageously, the embodiment of  FIG. 25  allows adjustability of the entry and exit points away from the tool body  1925 , creating a dead area  1930  in the fluid flow where high velocities and turbulence do not exist and directing fluid away from the retainer  1920  and tool body  1925  made of the soft, drillable material which is more susceptible to erosion due to fluid flow than the harder material of the flow tube  1910 . 
     An alternate embodiment of a nozzle assembly  2000  of the present invention is shown in  FIG. 26 . The nozzle assembly  2000  is substantially similar to the nozzle assembly  1900  shown and described in relation to  FIG. 25 ; therefore, like parts are labeled with like numbers (the last two digits of the numbers are the same). The difference between the assembly  2000  and the assembly  1900  is that the entire nozzle assembly  2000 , including the nozzle retainer  2020  and the flow tube  2010 , may be constructed of a soft, drillable material such as copper or plastic or of a non-drillable material (such as when used in a retrievable cutting structure rather than a drillable cutting structure, as described below). This design allows for ease of construction of the nozzle assembly  2000  because the nozzle assembly  2000  can be made in one piece. No adhesive  1945  is required in the embodiment of  FIG. 26  because the nozzle assembly  2000  is one piece. The embodiment shown in  FIG. 26  may be utilized in drilling applications when the flow regime is such that easily drillable materials such as copper or plastic may be used while still gaining the benefits of the removal of localized turbulence from the tool body  2025  itself due to the straight-bore flow tube  2010 . This design allows for sleeving of the inner diameter of the flow tube  2010  by platting, shrink fitting, or any other suitable method to apply a wear-resistant material such as tungsten carbide and/or ceramic, where the thickness of the wear-resistant material is not so great as to detract from the process of drilling through the nozzle. The wear-resistant materials may be layered to obtain increased wear resistance and flexibility. 
     The nozzle assemblies  1900 ,  2000  shown in  FIGS. 25-26  allow for adjustment of the entry and exit standoff  1950  and  2050 ,  1960  and  2060  by moving the flow tube  1910 ,  2010  within the tool body  1925 ,  2025 . The flow tube  1910 ,  2010  may be moved towards the entry or exit point of the fluid from the flow tube  1910 ,  2010  as desired. 
       FIGS. 27 and 28  show further alternate embodiments of a nozzle assembly  2100 ,  2200 . The embodiment shown in  FIG. 27  includes the nozzle assembly  2100 , which includes a nozzle retainer  2120  and a flow tube  2180 . The flow tube  2180  is a profiled sleeve through which fluid flows from a tool such as a cutting structure attached to casing into the formation while jetting and/or drilling. In  FIG. 27 , the fluid enters into the flow tube  2180  from the left at an entry point and exits from the flow tube  2180  at an exit point. An inner diameter of the flow tube  2180  at the entry point of the fluid is larger than an inner diameter of the flow tube  2180  at the exit point of the fluid into the formation. Between the entry point of the fluid and a distance A along the flow tube  2180 , the flow tube  2180  is of a first inner diameter. The flow tube  2180  then converges at an angle over a distance B to a second inner diameter, which is smaller than the first inner diameter. The second inner diameter is maintained over a distance C along the flow tube  2180  until the exit point of the flow tube  2180 . 
     The flow tube  2180  is constructed from a relatively hard material such as ceramic, tungsten carbide, or PDC to limit erosion of the flow tube  2180 , as described in relation to  FIGS. 23A-B ,  24 A-B, and  25 - 26  above. The flow tube  2180  is relatively thin, as measured from the inner diameter of the flow tube  2180  to the outer diameter of the flow tube  2180 , to facilitate drilling through the relatively hard material of the flow tube  2180  by the subsequent cutting structure, as described above in relation to  FIGS. 25-26 . 
     A relatively soft, drillable material such as copper or plastic is utilized to form the nozzle retainer  2120 . The material making up the flow tube  2180  is harder than the material of the retainer  2120  and tool body  2125 , and the material of the flow tube  2180  is more resistant to corrosion than the material of the retainer  2120 . The drillability of the soft material allows the nozzle retainer  2120  to be of a larger thickness at the portion adjacent to the smaller diameter portion of the flow tube  2180  than its thickness at the other portions of the flow tube  2180 . The retainer  2120  inner diameter thus essentially conforms to the outer diameter of the flow tube  2180 . 
     The nozzle assembly  2100  is disposed in a tool body  2125 , which is preferably an earth removal member such as a drill shoe or a drill bit. The tool body  2125  is preferably constructed of a relatively soft (at least compared to the flow tube  2180 ), drillable material such as copper, aluminum, cast iron, plastic, or combinations thereof. The material of the tool body  2185  may or may not be the same as the material of the retainer  2120 . A seal  2105  is disposed within a seal groove  2107  formed in an outer diameter of the retainer  2120  to prevent fluid from traveling in the area between the inner diameter of the tool body  2125  and the outer diameter of the retainer  2120 . Retaining threads  2115  are located between the tool body  2125  and the retainer  2120  for connecting the nozzle assembly  2100  to the tool body  2125 . 
     The nozzle assembly  2100  is characterized by an extended exit. The extended exit is represented by an exit standoff  2160 , which is the length of the flow tube  2180  which extends past the end of the tool body  2125  from which fluid flows upon exit from the flow tube  2180 . The exit standoff  2160  diverts the flow turbulence into an area away from the nozzle retainer  2120  and the tool body  2125 . 
       FIG. 28  shows an additional embodiment of the present invention. The embodiment shown in  FIG. 28  is substantially the same as the embodiment shown in  FIG. 27 ; therefore, substantially similar elements to  FIG. 27  which are in the “21” series are labeled in  FIG. 28  with the “22” series. The difference between the embodiment of  FIG. 27  and the embodiment of  FIG. 28  is that the embodiment shown in  FIG. 28  not only includes the extended exit in the form of the exit standoff  2260 , but also includes the extended entry in the form of the entry standoff  2250 . The entry standoff  2250  is the length of the flow tube  2280  which extends past the end of the tool body  2225  into which fluid flows upon entry into the flow tube  2280 . The extended entry of fluid through the flow tube  2280  provides an area of low turbulence next to the tool body  2225  at entry. In addition to their use in drillable application, the embodiments of  FIGS. 27 and 28  may all be utilized in non-drillable applications such as in expandable cutting structures when drilling with casing. 
     Shown in  FIG. 29  is an embodiment of an earth removal member  1925  (“tool body”), preferably a cutting structure in the form of a drill shoe or drill bit, which includes two nozzle assemblies  1900  therein. The nozzle assemblies  1900  are shown, but one or more of the nozzle assemblies  2000 ,  2100 ,  2200  may alternately be disposed within the tool body  2125 . The upper nozzle assembly  1900  shown in  FIG. 29  is oriented at an angle with respect to the vertical axis of the casing connected to the tool, thus illustrating the use of the nozzle assembly  1900 ,  2000 ,  2100 ,  2200  to directionally drill by jetting through a fluid diverter, or an oriented nozzle or jet, as shown and described in relation to  FIGS. 14-15  and  17 .  FIG. 29  also demonstrates by the lower nozzle assembly  1900  shown in the figure that the nozzle assembly  1900 ,  2000 ,  2100 ,  2200  may also be utilized in casing drilling operations which do not involve nudging and directionally drilling. 
     In addition to their use in drillable applications, the above embodiments shown in  FIGS. 25-29  may also be utilized in a retrievable cutting structure when a retrievable cutting structure is used with the embodiments of the invention shown in  FIGS. 1-22 , such as an expandable bit. The embodiment of  FIG. 26  is especially applicable to non-drillable nozzles, where protection of the tool body  2025  at the entry and exit points is required, or when it is required to position the nozzle exit point closer to the formation. 
       FIG. 30  is a cross-sectional view of the lower end of a cutting structure having nozzles therethrough. In directional jetting, as shown and described in relation to  FIGS. 14-15  and  17 , one or more of the nozzles of the cutting structure may be blocked to prevent fluid flow therethrough. The unobstructed nozzles will produce selective fluid flow from only a portion of the cutting structure, so that fluid flow is asymmetrically introduced into the wellbore and forms a diverted path for the casing within the formation. 
     The alternate embodiments of  FIGS. 53A ,  53 B, and  54  provide drill bit nozzles that are constructed to withstand the abrasive and erosive impact of jetted drilling fluid, while also being suitable for subsequent drilling operations intended to drill through drill bit bodies to which the nozzles are attached, and indeed the nozzles themselves. The embodiments of  FIGS. 53A-B  and  54  further provide a method of drilling a wellbore, wherein the drilling method is that commonly known as drilling with casing and wherein subsequent drilling may be undertaken by a subsequent drill bit, without the requirement of the removal of the earlier or first drill bit from the well bore, and wherein the earlier or first drill bit includes nozzles. 
       FIGS. 53A-B  and  5  show embodiments of a new and improved drill bit nozzle comprising a body defining a through-bore, wherein the through-bore defines a passage for drilling fluid in use, wherein the surface of the through-bore within the body has a relatively high resistance to erosion and wherein the nozzle is characterized in that the body is made substantially of a material or materials that allow for the nozzle to be subsequently drilled through by standard wellbore drilling equipment. Preferably, the through bore has an enlarged concave portion at an inlet side of the nozzle, communicating with a smaller diameter cylindrical portion. 
     The nozzle body may be made of two materials, wherein the surface of the through-bore is made of a first material, wherein said first material is of relatively thin construction and has a high resistance to erosion, and wherein the remainder of the nozzle body is made of a second material that is easily drillable. The first or surface material may be a hard chrome. Alternatively, tungsten carbide or suitable alloys may be used, their suitability being assessed by their ability to withstand erosive forces from the well fluid jetted through the through-bore. 
     The second material forming substantially the majority of the nozzle body may be made typically of a softer metal, such as nickel, aluminum, copper or alloys of these. Preferably, the second material may be copper and the surface or first material is hard chrome, wherein the hard chrome is applied to the copper body by electro-plating. 
     Alternatively, a nozzle in accordance with the present invention may be made of a rubber material. In this respect, it is noted that while rubber is typically not a “hard” material, it does nevertheless have a high resistance to erosion. Moreover, rubber materials may be easily drilled by subsequent drilling bits. A nozzle in accordance with invention may be made of one or more materials and need not be made entirely or even partially of a metal material. Polyurethane or other elastomers may also be used. 
     Referring firstly to  FIGS. 53A and 53B , there is shown a drill bit nozzle  1 . The drill bit nozzle  1  is adapted to be threadably engaged with a drill bit body (not shown) by virtue of the threaded portions  2 . The nozzle  1  is provided with an annular body  3  that defines a through-passage or through-bore  4 . The through-bore  4  is formed with an inlet having a concave enlarged portion  4   a  which communicates with a cylindrical smaller diameter portion  4   b  leading to an outlet  7 . The geometry of the through-bore  4  is such that well fluid is jetted at high velocity out the outlet  7 . 
     It is recognized in the invention that the nozzle through-bore  4  is intended to receive drilling fluid at high velocities and with high pressure differentials. Accordingly, the surface  5  of the through-bore  4  is constructed of a material that is suitable for withstanding the abrasive and eroding nature of the drilling fluid in use. Not only must the surface of the through-passage withstand the eroding forces of the drilling fluid, but in view of the proximity of the nozzles to the cutting surface of the drill bit, excessive wear may be induced in the event of a nonresistant material being employed as a result of the impact of small rock particles and other debris cut by the drill bit from the well formation. The erosive effect of rock particles within drill bit nozzles is well known and documented. For this reason, the surface of the through-bore  4  is preferably made from a hard material which, in an example embodiment of  FIGS. 53A-B , is a hard chrome material. In another example, tungsten carbide may be used as the surface material. 
     The surface material will typically be chosen as one which is able to be combined with a softer, drillable material whereby this softer, drillable material may form substantially the body of the drill bit nozzle, with the exception of the surface herein before mentioned. In the example embodiment illustrated in  FIG. 53A-B , the second material from which substantially all of the nozzle body is made is copper. Copper is selected as one suitable material as the surface coating of hard chrome may be easily applied to the copper body by electro-plating means. Additionally, copper is sufficiently soft to allow a subsequent drill bit to drill through the body of the nozzle. 
     In  FIG. 54 , an alternative nozzle  12  is made substantially of a single non-metallic material, preferably rubber. However, to enable the rubber nozzle  12  to be attached to a drill bit body, the nozzle  12  is provided with a threaded insert made of a metallic material. The threaded insert  11  is, nevertheless, made of a material which is sufficiently soft to allow a subsequent drill bit to drill through it. 
     An advantage of the present invention will be apparent from the method of use of the drill bit nozzle as shown in  FIGS. 53A-B  and  54  and described above which allows for a drill bit bearing drill bit nozzles to be left in a wellbore during the cementing of casing and subsequently drilled through by standard wellbore drilling equipment to allow for the well to be extended. The invention may be seen to overcome the difficulty of providing drill bit nozzles in a manner that allowed for their resistance to wear from the erosive characteristics of jetted drilling fluid, while nevertheless enabling subsequent conventional or standard wellbore drilling equipment to drill through them. 
     When nudging casing into the formation, it is sometimes useful to form a casing string made up of a plurality of casing sections. Making up the casing string involves rotating one casing section relative to another casing section to threadedly connect the casing sections together. Many of the directional drilling tools described in the figures of the present application include biasing tools (e.g., eccentric stabilizer and/or directional jet) disposed on the casing or within the casing, the location of which must be tracked from the surface of the wellbore to allow the operator to maintain the direction and angle of the deviated wellbore while drilling with the casing. One method of tracking the position of the biasing tool on the casing involves marking the position of the biasing tool when the casing having the biasing tool thereon is first lowered into the formation (“stoking or scribing in the hole”). Marking the position may be accomplished by drawing a vertical chalk line along the casing as one casing section is threaded onto another. Then, when the made-up casing string is lowered into the wellbore, the portion of the marked casing section which remains located above the wellbore (e.g., by a spider on a rig floor) becomes the reference point for marking a chalk like after the next section of casing is threaded onto the casing string. 
     An additional method of tracking the position of the biasing tool, which may be used in addition to the scribing method, is accomplished by the mechanism shown in  FIG. 31 . A casing string  2300  which may be utilized in the present invention while jetting into the formation includes a casing section  2320  having male threads  2321  threaded to a casing section  2330  having male threads  2331  by a collar  2315  having female threads  2311  and  2312 . Disposed within the collar  2315  is a buttress torque ring  2310 . The buttress torque ring  2310  is a spacer placed in between the ends of the pins  2331 ,  2321  of the casing sections  2330 ,  2320  to provide a stop mechanism to stop torquing of the casing sections  2330 ,  2320  at a given point. The buttress torque ring  2310  may be used to hold the chalk line when scribing in the hole so that the chalk mark does not lose accuracy as to the location of the biasing tool because the rotational position of the casing sections  2330 ,  2320  relative to one another changes. 
     Additional embodiments of the present invention generally provide improved methods and assemblies for drilling with casing (DWC). In contrast to the prior art, drilling assemblies according to the present invention are supported between an attachment point at a bottom of the casing and the point of drilling contact by one or more adjustable stabilizers. The stabilizers may have one or more adjustable support members that may be placed in a first (run-in) position giving the stabilizer a sufficiently small outer diameter to be run in through the casing with the drilling assembly. The support members may then be placed in a second position giving the stabilizer a sufficiently large outer diameter to engage an inner wall of the wellbore to provide support for the drilling assembly during drilling. 
     Additional embodiments of the present invention provide directional force for directionally drilling the assembly on the casing rather than the BHA. Moreover, embodiments of the present invention reduce the requisite length of the rat hole below the casing, thereby decreasing the amount by which the casing must be lowered into the rat hole after the BHA has drilled to the desired depth at which to place the casing within the wellbore. 
     For different embodiments, the drilling assemblies of the present invention may be adapted to operate in either a rotary or slide mode. For some embodiments, in an effort to decrease drilling time, an expandable bit having a higher removal rate than the conventional combination of an under-reamer and pilot bit may be utilized. While embodiments of the present invention may be particularly advantageous to directional drilling with casing, some embodiments may also be used to advantage in non-directional DWC systems. Such embodiments may lack the bent subassemblies shown in the following figures. 
       FIGS. 33A-D  illustrate an exemplary DWC system for directionally drilling of a wellbore  4102  through a formation  4103  utilizing a drilling assembly, according to an embodiment of the present invention, comprising a bottom hole assembly (BHA)  4200  attached to a portion of casing  4104 . As illustrated, the drilling assembly generally includes at least one adjustable stabilizer  4202 . For some embodiments, the adjustable stabilizer  4202  may be positioned to provide support to the BHA  4200  between a casing latch  4106  and a earth removal member or drilling member, such as an expandable bit  4204 . Accordingly, the adjustable stabilizer  4202  may decrease the amount of deflection of the BHA  4200 , thereby improving directional control, increasing bit life, and increasing formation removal rate. 
     As illustrated, for some embodiments, the stabilizer  4202  may be positioned above a biasing member, such as a bent subassembly  4114  (“bent sub”) used to bias the BHA  4200  in the desired direction. The bent sub  4114  may be fixed or adjustable to tilt the face of the bit  4204 , typically from 0° to approximately 3° with respect to the centerline of the BHA  4200 . As previously described, the bent sub  4114  may be integral with a downhole motor  4112 . The number of adjustable stabilizers  4202  utilized in a system may depend on a number of factors, such as the weight-on-bit applied to the BHA  4200 , the length of the BHA  4200 , desired wellbore trajectory, etc. 
     While a conventional pilot bit and under reamer may be used for some embodiments, the expandable bit  4204  generally provides an increased removal rate and performs the same operations (e.g., forming an expanded hole below the casing  4104 , allowing the casing string to advance with the wellbore). The increased removal rate may be accomplished by providing a greater density of cutting elements (“cutter density”) in contact with the wellbore surface. For example, cutting members  4205  of the bit  4204  may include cutting elements arranged in full complement with the hole profile to achieve an optimal penetration rate. An example of an expandable bit is disclosed in International Publication Number WO 01/81708 A1, which is incorporated herein in its entirety. As described in the above referenced publication, cutting elements of the bit  4204  may be made of any suitable hard material, such as tungsten carbide or polycrystalline diamond (PDC). 
     Operation of the BHA  4200  may be best described with reference to  FIG. 34 , which illustrates a flow diagram of exemplary operations  3300  for directional DWC, according to one embodiment of the present invention. At step  3302 , a drilling assembly (e.g., the BHA  4200 ) is run down a wellbore  4102  through casing  4104 , the drilling assembly having an (at least one) adjustable stabilizer  4202  and an expandable bit  4204 . As illustrated in  FIG. 33A , in order to run the BHA  4200  through the casing  4104 , support members  4203  of the stabilizer  4202  and cutting members  4205  of the expandable bit  4204  may be placed in a first (run-in) position, wherein the stabilizer  4202  and expandable bit  4204  each have a total outer diameter less than the inner (drift) diameter of the casing  4104 . The BHA  4200  is generally run until a securing mechanism, such as a casing latch  4106 , is aligned with a bottom portion of the casing  4104 . At step  3304 , the drilling assembly is secured to a bottom portion of the casing  4104 , for example, with the casing latch  4106 . 
     At step  3306 , the bit  4204  is expanded to have an outer diameter greater than an outer diameter of the casing  4104 . For example, as illustrated in  FIG. 33B , the cutting members  4205  of the expandable bit  4204  may be expanded into an open position. Generally, movement of the cutting members  4205  between the retracted and expanded positions may be controlled through the use of hydraulic fluid flowing through the center of the expandable bit. For example, increasing the hydraulic pump pressure (i.e., by increasing the flow of drilling fluid) may move the cutting members  4205  into the expanded position while decreasing the hydraulic pressure may return the blades to the retracted position (e.g., for retrieval of the BHA  4200  after drilling operations are completed, for bit replacement, etc.). 
     At step  3308 , the stabilizer  4202  is adjusted for directional control of the drilling assembly. For example, initially, an outer diameter of the stabilizer  4202  may be adjusted from the first (run-in) position to a second position having a sufficiently large diameter to engage the inner walls of the wellbore  4102  to support the BHA  4200  while drilling. During the drilling process, as will be described in greater detail below, the stabilizer  4202  may be adjusted to a third position (between the run-in position and the second position) to vary the under-gage amount (e.g., separation between support members  4203  and the inner walls of the wellbore  4102 ), in an effort to control the trajectory of the hole. 
     Means for adjusting the stabilizer  4202  may vary with different embodiments. For example, as illustrated in  FIGS. 33A-33C , the support members  4203  may be implemented as movable arms/blades that may be retracted in the first (run-in) position ( FIG. 33A ), expanded in the second position, and partially retracted/expanded to the third position ( FIG. 33C ) to provide a separation between the stabilizer  4202  and the wellbore  4102 . The stabilizer  4202  may be continuously adjustable to aid in directional control. As an alternative, one or more of the support members  4203  may be aligned to give the stabilizer  4202  a smaller diameter during run-in. The support members  4203  may then be misaligned (e.g., by rotating one of the support members  4203  relative to the other) to increase the diameter of the stabilizer  4202 . As another alternative, the stabilizer  4202  may include one or more spring-type support members  4207  (shown in  FIG. 33D ) that may be adjusted between the first, second, and third positions. As yet another alternative, the stabilizer  4202  may include an inflatable or mechanical support member (not shown), that may be operated similar to a packing element to adjust the stabilizer between the first, second, and third (or more) positions. 
     In either case, adjustments to the stabilizer  4202  (between the various positions) may be made by any suitable means, such as hydraulic means (in a similar manner as described above with reference to the expandable bit  4204 ), mechanical means, and electrical or electro-mechanical means, etc. Regardless, the stabilizer  4202  may be designed for use in rotary and/or slide mode. For example, in slide mode, the stabilizer  4202  provides drill string centralization and prevents the BHA from leaning onto one side of the hole. For some embodiments, the stabilizer  4202  may include sensors that monitor relative movement of the casing  104  in order to allow the stabilizer  4202  to rotate with the casing  4104  or to slide as the casing  4104  is being rotated to aid in the control of the direction of the hole. In either case, the stabilizer  4202  may prevent BHA  4200  from buckling (and leaning to one side) when weight-on-bit is applied to the BHA  4200 . By preventing deflection of the BHA  4200  within the wellbore  4102 , the stabilizer  4202  may also reduce the amount of axial and lateral vibration. 
     As previously described, excessive vibration, particularly in rotary mode, may lead to less than optimal contact between the bit  4204  and the formation  4103 , leading to reduced penetration rate and a corresponding increased drilling time, which increases production costs. Further, excessive vibration may also lead to catastrophic harmonics which may damage and/or destroy the various components of the BHA  4200 . In an effort to further reduce vibration, the BHA  4200  may also include a flexible collar  4206 , which may be designed to prevent vibration from traveling from the bent subassembly  4114  to an upper portion of the BHA  4200  (e.g., any portion above the flexible collar  4206 ). The flexible collar  4206  may be made of any suitable flexible-type materials capable of withstanding harsh downhole conditions. 
     At step  3310 , the bit  4204  is rotated to drill a hole having an outer diameter larger than the outer diameter of the casing  4104 . As previously described, embodiments of the BHA  4200  may be operated in a rotary mode or a slide mode. In rotary mode, the bit  4204  may be rotated with the casing  4104  and guided with a rotary-steerable assembly (not shown), having adjustable pads that may be used to “push off” the inner walls of the formation  4102  to adjust the deviation of the bit angle from center. In slide mode, the bit  4204  may be rotated by a steerable downhole motor  4112 , which typically provides a high speed of rotation and a high rate of removal without the need to rotate the casing  4104 . When operating in either mode, the stabilizer  4202  provides centralization and prevents the BHA  4200  from leaning to one side of the hole, thus allowing better control of the trajectory of the hole. 
     At step  3312 , the trajectory of the hole is monitored. As previously described, in conventional DWC systems, the hole may be steered by geological indicators logged at certain points while drilling (logging while drilling, or “LWD”) using at least one LWD tool. While this log may be used to reconstruct and verify the wellbore path after drilling, this may be too late to make corrections. However, by monitoring the trajectory of the hole while it is being drilled (measuring while drilling, or “MWD”), embodiments of the present invention may allow for corrections to be made at the surface, for example by adjusting weight on bit, adjusting angle of the bent sub, and/or steering the motor  4112 . 
     Further, as previously described, the stabilizer  4202  may be adjusted in response to a monitored trajectory. For example, the support members  4203  may be adjusted to provide a separation between the stabilizer  4202  and the inner surface of the wellbore  4102 . The separation between the stabilizer  4202  and the inner surface of the wellbore  4102  (as shown in  FIG. 33C ) may allow the bent housing  4114  of the motor  4112  to lean more to one side, thus increasing bit deflection. Accordingly, the under-gage of the stabilizer  4202  may be varied, for example, in an effort to control bit deflection of the bit from center, for example, to make relatively fine adjustments to the trajectory of the wellbore  4103  as it is extended. 
     The trajectory of the wellbore  4102  may be monitored with a measurement-while-drilling (MWD) tool  4107  which, as shown, may be disposed anywhere along the BHA  4200 . The MWD tools  4107  may be generally used to evaluate the trajectory of the wellbore  102  in three-dimensional space while extending the wellbore  4102 . Therefore, the MWD tool  4107  may generally include one or more sensors to measure the trajectory (e.g., azimuth and inclination) of the wellbore, such as a steering sensor, accelerometer, magnetometer, or the like. 
     Of course, the MWD tool  4107  may also have sensors to monitor one or more downhole parameters, such as conditions in the wellbore (e.g., pressure, temperature, wellbore trajectory, etc.) and/or geophysical parameters (e.g., resistivity, porosity, sonic velocity, gamma ray, etc.). For some embodiments, the MWD tool  4107  may log such parameters for later retrieval at the surface. Thus, the MWD tool  4107  may also perform the same functions as conventional LWD tools. Regardless of whether these parameters are logged or telemetered to the surface in real time, measuring these parameters while drilling may save an additional trip down the wellbore for the sole purpose of such measurements. 
     Any suitable telemetry techniques may be utilized to communicate the wellbore trajectory (and possibly any other parameters) monitored by the MWD tool  4107  to the surface of the wellbore  4102 . Examples of suitable telemetry techniques may include electronic means (e.g., through a wireline or wired pipe) and/or digitally encoding data and transmitting to the surface as pressure pulses in a mud system using sensing devices including, but not limited to, one or more of the following: mud-pulse telemetry device; mud pulse on gyroscope device; gyroscopic telemetry device on wireline; gyroscopic telemetry electromagnetic device; gyroscopic telemetry acoustic device; gyroscopic telemetry mud pulse device; magnetic dipole including single shot and telemetry; wired casing as shown and described in relation to U.S. application Ser. No. 10/419,456 entitled “Wired Casing” and filed Apr. 21, 2003, which is incorporated by reference herein in its entirety; and fiber optic sensing devices. Any combination of sensors and/or telemetry may be utilized in the present invention. Regardless of the method used, based on the monitored trajectory as received at the surface, adjustments may be made at the surface (e.g., adjustments to the stabilizer  4202 , weight on bit, speed of rotation, steering of the motor  4112  or rotary-steerable assembly, etc.). 
     Accordingly, the operations  3308 - 3310  may be repeated to extend the wellbore to a desired depth along a well-controlled trajectory. Once the desired depth is reached, the BHA  4200  may be retrieved from the wellbore. For example, the BHA  4200  may be retrieved by unlatching the casing latch  4106  and placing the stabilizer  4202  and expandable bit  4204  back in the run-in positions (as shown in  FIG. 33A ) and pulling the BHA  200  back to the surface through the casing  4104 . The string of casing  4104  may then be extended into the newly drilled portion of the wellbore, for example by adding sections of casing  4104  from the surface. 
     However, retrieving the BHA  4200  through the entire length of casing  4104  may require a significant amount of time in which the formation around the newly drilled (and uncased) portion of the wellbore may settle, thereby making it difficult to subsequently advance the string of casing  4104 . Therefore, for some embodiments, prior to completely retrieving the BHA  4200 , the BHA  4200  may be only partially raised through the casing  4104  (e.g., enough that the bit  4205  is at least partially within the casing  4104 ). After partially raising the BHA  4200 , the casing  104  may then be advanced into the newly drilled portion of the wellbore, for example, by adding additional sections of casing  4104  from the surface. Because partially raising the BHA  4200  may require significantly less time than completely raising the BHA  4200  to the surface (as during retrieval), the likelihood of the formation settling prior to advancing the casing  4104  is reduced. After advancing the casing  4104 , the BHA  4200  may then be completely retrieved. 
     While the adjustable stabilizer  4202  is shown in  FIGS. 33A-33D  as positioned between the bit  4205  and casing latch  4106 , for some embodiments, one or more adjustable stabilizers may be positioned above the casing latch  4106  instead of, or in addition to, the adjustable stabilizer  4202 . As an example, an adjustable stabilizer  4202  may be positioned above the casing latch  4106  to provide support to the casing  4104 , which, when utilized as part of the drilling assembly (including the BHA  4200 ), may also be subjected to similar strains as the BHA  4200 . In other words, the casing  4104  may also be subjected to weight on bit and, particularly in the case of rotary operation, lateral and radial vibrations. Further, while not shown, a drilling assembly may include the BHA  4200  attached to a portion of casing run in through another portion of casing (not shown) already lining the wellbore. For example, the BHA  4200  may be attached to a portion of expandable casing. After extending the wellbore with the BHA  4200 , the expandable casing may be advanced and expanded to line the extended portion of the wellbore. Of course, the BHA  4200  may be retrieved from the wellbore prior to the expanding. 
     In another embodiment, the expandable bit  4205  may be replaced with a combination of a pilot bit and underreamer. Embodiments of the present invention provide methods and assemblies for improved drilling with casing (DwC). By providing an adjustable stabilizer, the drilling assembly may be adequately supported, thus avoiding excessive deflection and vibration that commonly occurs in conventional DwC systems. Further, by utilizing measurement-while-drilling equipment, trajectory of the wellbore may be measured in real time, thus allowing corrections of the trajectory to be made at the surface increasing the likelihood a desired trajectory will be achieved. A further additional embodiment may include closed-loop drilling to control the diameter of the adjustable stabilizer or motor bend angle, or a 3-D rotary steerable system. The closed-loop control could be a microprocessor, either uphole or downhole. 
       FIGS. 35-36  show alternate embodiments of a system for directionally drilling with casing. These embodiments provide methods and apparatus for drilling with a BHA releasably attached to casing which allow the directional force for the system to be placed directly on the casing rather than directly on the BHA. 
       FIG. 35  shows casing  2404  with a BHA  2400  releasably attached to an inner diameter thereof by a casing latch  2406 . While a casing latch  2406  is shown in  FIG. 35 , any other method for releasably attaching the BHA  2400  to the inner diameter of the casing latch  2406  is contemplated for use in the present invention. The casing latch  2406  performs an orientation function (described below) as well as the function of releasably connecting the casing  2404  to the BHA  2400 . To this end, one or more axial blades  2407  extend radially from the body of the casing latch  2406  portion of the BHA  2400 . Additionally, one or more torque blades  2405  located below the axial blades  2407  extend radially from the body of the casing latch  2406 . The torque blades  2405  may be included in any number, as with the axial blades  2407 . The axial blades  2407  and torque blades  2405  are spring-loaded. 
     The casing  2404  includes one or more casing sections.  FIG. 35  shows three casing sections  2404 A,  2404 B, and  2404 C threadedly connected to one another. The lower casing section  2404 C is threadedly connected to the middle casing section  2404 B by a casing coupling  2416 . The casing coupling  2416  may have female threads at upper and lower ends for threadedly connecting the lower end of the middle casing section  2404 B to the upper end of the lower casing section  2404 C, respectively. Likewise, the upper casing section  2404 A is threadedly connected to the middle casing section  2404 B by a profile collar  2411 . The profile collar  2411  may have female threads at each end for connecting to the male threads of the lower end of the upper casing section  2404 A and to the upper end of the middle casing section  2404 B. The profile collar  2411  includes profiles  2413  therein for releasably engaging the axial blades  2407  and profiles  2415  therein for releasably engaging the torque blades  2405 . 
     When employed to connect the BHA  2400  to the casing  2404 , the BHA  2400  with the spring-loaded axial and torque blades  2407  and  2405  are run through the casing  2404 . Once the blades  2407  and  2405  reach the profiles  2413  and  2415  in the inner diameter of the profile collar  2411 , the bias force from the spring-loaded blades  2407  and  2405  causes the blades  2407  and  2405  to snap out into their respective profiles  2413  and  2415 . The torque blades  2405  rotate a few degrees before snapping out into the profile collar  2411 . The axial blades  2407  prevent the BHA  2400  from translating axially relative to the casing  2404 , and the torque blades  2405  prevent the BHA  2400  from rotating relative to the casing  2404 . While the profiles  2415  and  2413  are shown existing in the profile collar  2411  in  FIG. 35 , it is also contemplated for use in the present invention that profiles may exist in the casing  2404  itself to releasably engage the axial and torque blades  2407  and  2405 . 
     An upper portion of the BHA  2400 , shown here as the upper position of the casing latch  2406 , possesses one or more packing elements  2417  on its outer diameter for sealingly engaging an annulus between the BHA  2400  and the casing  2404 . The packing elements  2417  are preferably elastomeric for providing a seal between the casing  2404  and the BHA  2400 . Additionally, cups  2418  located above and below the packing elements  2417  aid in sealing the annulus between the casings  2404  and the BHA  2400 . The packing elements  2417  and the cups  2418  extend radially from the BHA  2400  circumferentially around the body of the casing latch  2406 . 
     The upper end of the casing latch  2406  has threads  2419 , preferably female threads, and/or a fishing profile to allow collets to latch into or around (see U.S. Pat. No. 3,951,219, which is herein incorporated by reference in its entirety) for connecting the BHA  2400  to the surface with a tubular body (not shown) so that the BHA  2400  can be retrieved at the desired time. Additionally, the upper end may have a GS profile. Possible tubular bodies which may retrieve the BHA  2400  include but are not limited to drill pipe, coiled tubing, coiled rod, or wireline. Below the casing latch  2406  in the BHA  2400  is a resistivity sub  2420  for housing one or more resistivity sensors (not shown) therein for use in taking real-time or periodic resistivity measurements. Around the resistivity sub  2420  is a stabilizer  2422  which extends radially from and preferably circumferentially around the BHA  2400 . The stabilizer  2422  bridges the annulus between the BHA  2400  and the casing  2404  and maintains the position of the BHA  2400  within the casing  2404  at a preferred axial location to stabilize the BHA  2400  relative to the casing  2404 . 
     The resistivity sub  2420  may contain one or more geophysical sensing devices capable of measuring parameters such as formation resistivity, formation radiation, formation density, and formation porosity. The sensing devices may be latched therein by embodiments of mechanisms shown in  FIGS. 42-47  (see below). The section of casing (here, the middle casing section  2404 B) disposed around the portion of the BHA  2400  having the resistivity device therein preferably has one or more resistivity antennas for use with the resistivity device. The resistivity sub  2420  is not required for use in the present invention, but only when resistivity measurements are desired during or after drilling. 
     Below the resistivity sub  2420  in the BHA  2400  is an MWD/LWD sub  2424 , which may house one or more MWD or LWD sensing devices including, but not limited to, one or more of the following: mud-pulse telemetry device; mud pulse on gyroscope device; gyroscopic telemetry device on wireline; gyroscopic telemetry electromagnetic device; gyroscopic telemetry acoustic device; gyroscopic telemetry mud pulse device; magnetic dipole including single shot and telemetry; wired casing as shown and described in relation to U.S. application Ser. No. 10/419,456 entitled “Wired Casing” and filed Apr. 21, 2003, which is incorporated by reference herein in its entirety; and fiber optic sensing devices. Any combination of sensors and/or telemetry may be utilized in the present invention. As with the resistivity sub  2420  sensing devices, the MWD/LWD sub  2424  sensing devices may be latched therein by the mechanism shown in  FIGS. 4-472 . The sensing device(s) within the MWD/LWD sub  2424  are utilized to measure the angle with respect to the vertical axis of the casing  2404  at the surface of the earth to which the casing  2404  is deflected. The angle may be measured in real time while drilling the casing  2404  into the earth while the surveying tool remains within the MWD/LWD sub  2424 , or alternatively, the angle may be measured periodically by halting drilling temporarily to lower the surveying tool into the MWD sub  2424  and measure the orientation of the casing  2404 . Measuring the angle at which the casing  2404  is being or has been drilled allows the operator to adjust conditions, such as amount of drilling fluid flowed through the casing  2404  or the force placed on the casing  2404  from the surface to lower the casing  2404  into the earth formation, to alter the angle of deflection of the casing  2404  within the formation. 
     Because same directional MWD and LWD sensors are magnetic, the casing  2404  surrounding the MWD/LWD sub  2424  must usually be non-magnetic. However, because the casing  2404  is left downhole when drilling with casing, and because non-magnetic casing is more expensive than the magnetic casing usually drilled with when drilling with casing, it is desirable in some situations to drill with magnetic casing. To this end, a gyroscope may be utilized as the directional MWD/LWD sensor to eliminate the necessity to use non-magnetic casing around the MWD/LWD sub  2424 . Magnetic casing may then be disposed around the MWD/LWD sub  2424 . A preferred gyroscopic sensor for use in the present invention is a Gyrodata Gyro-Guide GWD gyro-while-drilling tool, as shown and described in Gyrodata Services Catalog, 2003, at page 31. Gyro-Guide is a fully integrated guidance system housed in the MWD tool string (here, the BHA  2400 ) which includes wireless telemetry for surveying while drilling. Use of the Gyro-Guide allows gyro-while-drilling rather than the operator having to repeatedly stop the drilling process, place the surveying tool (e.g., gyroscope) into the casing  2404  with wireline, take measurements, then remove the surveying tool prior to drilling further. 
     Below the MWD/LWD sub  2424  in the BHA  2400  is a mud motor  2425 . Connected below the mud motor  2425  is an underreamer  2426  and a pilot bit  2428 . The pilot bit  2428  and the underreamer  2426  may be replaced by a bi-center bit in one embodiment. The mud motor  2425  provides rotational force to the underreamer  2426  and pilot bit  2428  relative to the mud motor  2425  through a motor bearing pack  2429  when it is desired to rotate the pilot bit  2428  relative to the BHA  2400  and the casing  2404  and rotationally drill into the formation. The mud motor  2425  utilized may be similar to the mud motor shown and described in relation to  FIGS. 1-12 . The pilot bit  2428  and underreamer  2426  drill the casing  2404  into the formation. The pilot bit  2428  preferably has side cutting capability to allow the casing  2404  to veer at an angle with respect to the centerline of the wellbore after drilling to the side of the wellbore. 
     An optional stabilizer  2430  similar to the stabilizer  2422  may be located around the outer diameter of the BHA  2400  at a location near the connection between the MWD/LWD sub  2424  and the mud motor  2425 . The stabilizer  2430  is preferably located adjacent to an eccentric casing bias pad  2435  (described below). Like the stabilizer  2422 , the stabilizer  2430  also maintains the axial location of the BHA  2400  relative to the casing  2404  by bridging the annulus between the BHA  2400  and the casing  2404 . An additional concentric stabilizer  2432  is disposed concentrically around the outer diameter of the mud motor  2425  near the lower end of the casing  2404  to stabilize the lower end of the BHA  2400  relative to the casing  2404 . 
     The primary impetus for the directional bias of the casing string  2404  (with respect to the vertical axis of the casing string  2404  entering the formation from the surface) exists due to an eccentric casing bias pad  2435 . The casing bias pad  2435  is disposed on only one side of the casing  2404  on the outer diameter of the casing  2404  to push the centerline of the casing  2404  at an angle with respect to the wellbore centerline, thus eccentering the casing  2404  relative to the wellbore. The casing bias pad  2435  is mounted near the lower end of the casing  2404 . The directional bias angle of the casing  2404  is in the opposite side of the casing  2404  from the side of the casing  2404  to which the casing bias pad  2435  is attached. For example, as shown in  FIG. 35 , the eccentric bias pad  2435  is located on the right side of the casing  2404 ; therefore, the deviation angle of the casing  2404  will be to the left of the centerline of the wellbore. In one embodiment, the casing bias pad  2435  may cover approximately 90-100 degrees of circumference, but any angle is possible with the present invention. The height of the casing bias pad  2435 , or the distance from the inner side of the casing bias pad  2435  mounted on the outer diameter of the casing  2404  to the outer side of the casing bias pad  2435  farthest from the casing  404  outer diameter, is predetermined prior to insertion of the assembly into the wellbore. The height of the casing bias pad  2435  at least partially determines the angle at which the casing  2404  deviates from the centerline of the wellbore. In an additional embodiment of the present invention, the bias pad  2435  may instead be an eccentric stabilizer 
     With the eccentric casing bias pad  2435 , the directional force for directionally drilling the wellbore at an angle is provided essentially perpendicular to the portion of the casing bias pad  2435  perpendicular to the axis of the casing  2404 . The force is translated from the outer portion of the casing bias pad  2435  to the casing  2404  so that the directional force is primarily born by the casing  2404  rather than the BHA  2400 , primarily because the BHA  2400  is housed almost completely within the casing  2404  rather than a large portion of the BHA  2400  extending below the casing  2404 . In the embodiment shown in  FIG. 35 , the pilot bit  2428 , the underreamer  2426  and a portion of the mod motor  2425  are the only portions of the BHA  2400  which extend below the casing  2404 . Preferably, the length of the exposed BHA  2400  is approximately 5-10 feet in length. Ultimately, the directional bias force transmits from the wellbore, to the casing bias pad  2435 , to the stabilizer  2432 , through the motor bearing pack  2429 , and then to the underreamer  2426  and pilot bit  2428 . 
     The casing latch  2406 , in addition to performing the function of latching the BHA  2400  to the casing  2404 , orients the face of the MWD or LWD tool (not shown) located within the BHA  2400  to the casing bias pad  2435  so that the location of the casing bias pad  2435  on the casing  2404 , and consequently the angle at which the casing  2404  is drilling, is readily ascertainable with respect to some reference point. The torque blades  2405  of the casing latch  2406  maintain the rotational position of the BHA  2400  relative to the casing  2404 , therefore orienting the sensor with respect to where the eccentric pad  2435  is located by preventing rotation of the BHA  2400  within the casing  2404 . Similarly, the MWD/LWD tool may be latched into the MWD/LWD sub  2424  by the apparatus and method shown and described in relation to  FIGS. 42-47  so that the MWD/LWD tool does not rotate with respect to the casing latch  2406  body, thus maintaining the rotational position of the MWD/LWD tool with respect to the casing latch  2406  body so that the position of the eccentric bias pad  2435  is readily ascertainable. Thus, the operator can keep track of which in direction the casing  2404  is being drilled so that the wellbore can continue to be drilled in the same direction if desired. 
       FIG. 36  shows casing  2504  with a BHA  2500  releasably attached to an inner diameter thereof by a casing latch  2506 . As stated above in relation to  FIG. 35 , the casing latch  2506  may be substituted with any other means for attaching the casing  2504  to the BHA  2500 . The casing components including the casing sections  2504 A,  2504 B,  2504 C; profile collar  2511  including profiles  2513 ,  2515 ; and casing coupling  2516  are substantially similar to the casing sections  2404 A,  2404 B,  2404 C, profile collar  2411 , profiles  2413 ,  2415 , and casing coupling  2416  shown and described in relation to  FIG. 35 . Also, most of the BHA components including the threads  2519 ; packing element  2517  and cups  2518 ; axial and torque blades  2507  and  2505 ; resistivity sub  2520 ; MWD/LWD sub  2524 ; underreamer  2526 ; pilot bit  2528 ; and stabilizers  2522 ,  2530 , and  2532  are substantially similar to the threads  2419 , packing element  2417 , cups  2418 , axial and torque blades  2407  and  2405 , resistivity sub  2420 , MWD/LWD sub  2424 , underreamer  2426 , pilot bit  2428 , and stabilizers  2422 ,  2430 , and  2432 , as shown and described in relation to  FIG. 35 . Therefore, the above description of these components applies equally to the embodiment shown in  FIG. 36 . 
     The casing latch  2506  of  FIG. 36  is substantially similar to the casing latch  2406  of  FIG. 35 , so the majority of the above description of the casing latch  2406  applies equally to the embodiment shown in  FIG. 36 . The primary difference between the casing latch  2506  and the casing latch  2406  is that the casing latch  2506  of  FIG. 36  does not have to be an orienting latch to keep track of the location of the casing bias pad  2535 , as the casing bias pad  2535  of  FIG. 36  acts as a concentric stabilizer (see description below). 
     Instead of the mud motor  2425  of  FIG. 35 , a bent housing mud motor  2550  is connected to the lower end of the MWD/LWD sub  2524 . The bent housing mud motor  2550  includes a bent motor connecting rod housing  2555  that is bent at an angle to cause the casing  2504  to deviate while drilling at an angle with respect to the centerline of the wellbore. The bent motor connecting rod housing  2550  is angled with respect to the rest of the BHA  2500  at the angle and direction in which it is desired to bias the casing  2504 . 
     An additional difference between the system of  FIG. 35  and the system of  FIG. 36  is that rather than the eccentric casing bias pad  2435  of  FIG. 35 , the casing bias pad  2535  of  FIG. 36  is circumferential and can be termed a stabilizer. Rather than an eccentric bias pad providing the orientation angle of the casing  2504 , the bent motor connecting rod housing  2555  provides the orientation angle. 
     Just as in the embodiment of  FIG. 35 , the embodiment illustrated in  FIG. 36  shows a majority of the BHA  2500  located within the casing  2504 . The only portions of the BHA  2500  which are located below the casing  2504  are a portion of the bent motor connecting rod housing  2555 , the motor bearing pack  2529 , underreamer  2526 , and pilot bit  2528 . Again, the length of the BHA  2500  below the casing  2504  is preferably only approximately 5-10 feet. 
     In the operation of the embodiment of  FIG. 36 , the directional bias force is provided by the motor bend, which pushes against the side of the wellbore, causing a resultant force on the opposite side of the pilot bit  2528  and underreamer  2526 . However, the directional force is transmitted by the casing  2504  instead of the BHA  2500 , as in the embodiment of  FIG. 35 , so that the directional bias force transmits from the wellbore, to the casing bias pad  2535 , then to the stabilizer  2532 , through the motor bearing pack  2529 , and then to the underreamer  526  and pilot bit  2528 . 
     As in the embodiment shown in  FIG. 35 , the height of the casing bias pad  2535  is predetermined before lowering the assembly downhole. However, in the embodiment of  FIG. 36 , the mud motor bend angle is adjustable from the surface and/or downhole to adjust the angle at which the casing  2504  is drilled. In the embodiments of both  FIGS. 35 and 36 , the height and/or diameter of the casing bias pad  2435 ,  2535  (or eccentric stabilizer) is also adjustable from the surface of the wellbore and/or downhole. 
     In the embodiments of  FIGS. 35-36 , the non-magnetic casing section  2404 C or  2504 C may be constructed of any non-magnetic material consistent with MWD sensors. Also, other non-magnetic casing alternatives are contemplated for use with the present invention. The non-magnetic casing may be composite or metallic. Resistivity measurements from the resistivity sub  2420 ,  2520  may require repackaging of the sensor antennas and/or a special resistivity casing joint. 
     In the above embodiments shown and described in relation to  FIGS. 35-36 , in lieu of the underreamer  2426 ,  2526  and pilot bit  2428 ,  2528 , an expandable bit (not shown) which is expandable to drill the wellbore, then retractable to a smaller outer diameter when retrieving the BHA  2400 ,  2500  from the casing  2404 ,  2504  may be utilized. An example of an expandable bit which may be used in the present invention is described in U.S. Patent Application Publication No. US2003/111267 or U.S. Patent Application Publication No. 2003/183424, each of which is incorporated by reference herein in its entirety. 
     The BHA  2400 ,  2500  components, including the latch  2406 ,  2506 ; MWD/LWD sub  2424 ,  2524 ; and resistivity sub  2520 , may be arranged in a different order than is shown in  FIGS. 35-36 . Additionally, the stabilizers  2422 ;  2522 ;  2430 ,  2530 ; and  2432 ,  2532  may be placed in different longitudinal locations on the o.d. of the BHA  2400 ,  2500 . 
     The operation of embodiments depicted in  FIGS. 35-36  includes assembling the BHA  2400 ,  2500  and casing  2404 ,  2504 . The BHA  2400 ,  2500  and casing  2404 ,  2504  assembly is then lowered into the formation and the assembly is caused to drill at an angle with respect to a vertical wellbore drilled into the formation. If desired, the mud motor may rotate the pilot bit  2428 ,  2528  while drilling at the angle. Once the assembly has drilled to the desired depth at which to leave the casing  2404 ,  2504  within the wellbore, the BHA  2400 ,  2500  is detached from the casing  2404 ,  2504 . The casing  2404 ,  2504  is lowered over the BHA  2400 ,  2500 , and the BHA  2400 ,  2500  is then retrieved from the wellbore using a tubular body such as drill pipe or wireline. The casing  2404 ,  2504  may then be cemented into the wellbore. Additional casing (not shown) may then be drilled through the casing  2404 ,  2504  into the formation and may be expanded into the casing  2404 ,  2504 . This process may be repeated as desired. 
       FIG. 37  shows another embodiment of a directional drilling assembly. Particularly, the BHA  2700  is equipped with an articulating housing  2760  to provide the directional bias for drilling. As shown, the BHA  2700  is releasably attached to an inner diameter of the casing  2704  using a casing latch  2706 . As stated above in relation to  FIGS. 35 and 36 , the casing latch  2706  may be substituted with any other means for attaching the casing  2704  to the BHA  2700 . The casing components including the casing sections  2704 A,  2704 B,  2704 C; profile collar  2711  including profiles  2713 ,  2717 ; and casing coupling  2716  are substantially similar to the casing sections  2404 A,  2404 B,  2404 C, profile collar  2411 , profiles  2413 ,  2415 , and casing coupling  2416  shown and described in relation to  FIG. 35 . Also, most of the BHA components including the threads  2719 ; packing elements  2717  and cups  2718 ; axial and torque blades  2707  and  2705 ; resistivity sub  2720 ; MWD/LWD sub  2724 ; underreamer  2726 ; pilot bit  2728 ; and stabilizers  2722 ,  2730 , and  2732  are substantially similar to the threads  2419 , packing elements  2417 , cups  2418 , axial and torque blades  2407  and  2405 , resistivity sub  2420 , MWD/LWD sub  2424 , underreamer  2426 , pilot bit  2428 , and stabilizers  2422 ,  2430 , and  2432 , as shown and described in relation to  FIG. 35 . Therefore, the above description of these components applies equally to the embodiment shown in  FIG. 37 . 
     Instead of a bent motor  2550  as shown in  FIG. 36 , a drilling motor  2750  equipped with an articulating housing  2760  is used to provide torque to rotate the pilot bit  2728  and the underreamer  2726  as illustrated in  FIG. 37 . The articulating housing  2760  can be pivoted to create an angle between the drilling motor  2750  and the motor bearing pack  2729 , thereby causing the pilot bit  2728  to drill at an angle with respect to the centerline of the wellbore. In comparison to the bent motor  2550 , the articulating housing  2760  allows the drilling motor  2750  to pass through the casing  2404  in a substantially concentric manner. In this respect, a larger drilling motor may be installed on the bottom hole assembly, thereby providing more power to the pilot bit  2728 . 
       FIGS. 38A-B  depict an exemplary articulating housing  2760  according to aspects of the present invention. The articulating housing  2760  includes a first articulating member  2761  engageable with a second articulating member  2762  as shown in  FIG. 38A . In one embodiment, the first articulating member  2761  is connected to the drilling motor  2750 , and the second articulating member  2762  is connected to the motor bearing pack  2729 . As shown, the first and second articulating members  2761 ,  2762  are coupled using two male and female connections  2765 . Specifically, each of the male connection members  2763  of the first articulating member  2761  is coupled to a respective female connection member  2764  of the second articulating member  2762 . A pin  2766  may be inserted through each male and female connection  2765  to ensure engagement of the articulating members  2761 ,  2762 . Additionally, a sleeve  2767  may be disposed around the pins  2766  to prevent the separation of the pin  2766  from the connections  2765 . In turn, the sleeve may be attached to the articulating housing  2760  using another pin or screw  2769 . Optionally, the first articulating member  2761  may include one or more stabilizers  2768  formed thereon. 
       FIG. 38B  is another cross sectional view of the articulating housing  2760 , which is rotated 90 degrees when compared to  FIG. 38A . As shown, the second articulating member  2762  is deviated from the centerline of the first articulating member  2761 . This is because the pin connection  2765  acts like a hinge to allow relative rotation between the first and second articulating members  2761 ,  2762 . In this respect, the motor bearing pack  2729  and the pilot bit  2728  may be deviated from a centerline of the drilling motor  2750 . Preferably, the articulating housing  2760  is adapted to allow the motor bearing pack  2729  deviate up to about 7 degrees from the centerline; more preferably, up to about 5 degrees; and most preferably, up to about 3 degrees. 
       FIGS. 39-41  show another embodiment of a directional drilling assembly. In  FIG. 39 , a BHA  2900  is being conveyed through a casing  2904 . The BHA  2900  includes a casing latch  2906 , a MWD/LWD tool  2924 , an expandable stabilizer  2902 , and a flexible collar  2910 . The drilling motor  2950  is equipped with an articulating housing  2960  and a motor bearing pack  2929 . An expandable bit  2928  is employed to extend the wellbore. It must be noted that the description of the components provided herein applies equally to the embodiment shown in  FIGS. 39-41 . For example, the MWD/LWD tool  2924  may include sensors to monitor conditions in the wellbore such as pressure and temperature as previously described. During run-in, the expandable stabilizer  2902  and the expandable bit  2928  are collapsed. Additionally, the articulating housing  2960  is substantially vertical. When compared to a BHA having a bent motor, the articulating housing  2960  provides more clearance between the drilling motor  2950  and the casing  2904 . In this respect, a larger drilling motor may be used to generate more torque downhole. 
     In  FIG. 40 , the BHA  2900  has reached the bottom of the wellbore, but the drilling process has not started. As shown, the casing latch  2906  has been actuated to engage the BHA  2900  with the casing  2904 . It can also be seen that the articulating housing  2960  and the BHA  2900  are still substantially vertical. 
     In  FIG. 41 , the drilling process has begun. The articulating housing  2960  is actuated by applying weight to the housing  2960 . Because the expandable bit  2928  is in contact with the bottom of the wellbore, the housing  2960  experiences a force from above and below, thereby causing the housing  2960  to bend. In this manner, the expandable bit  2928  may be deviated from the centerline. Furthermore, the expandable stabilizer  2902  may be utilized to assist with direction control as discussed above. For example, the expandable stabilizer  2902  may be partially expanded and partially retracted as shown. Also, it can be seen that the expandable bit  2928  has been expanded to created larger diameter hole to accommodate the casing  2904 . 
     Referring initially to  FIG. 42 , there is shown, in cross-section, a wellbore  10 A in which drilling operations are being performed. Wellbore  10 A is a directionally drilled borehole, having an entry portion  12 A extending from the earth&#39;s surface  14 A to a deviated portion  16 A extending into a formation  18 A from which hydrocarbons are likely to be found. The borehole  10 A, although shown as having a generally dogleg profile, may have other profiles, such as deviating from vertical immediately upon entry to the earth. 
     To drill into the earth and thereby form borehole  10 A, a drill string  20 A, comprising a plurality of individual lengths of pipe or tubing  22 A (one such shown in  FIG. 43 ) and downhole equipment, such as a bent sub  30 A, drill bit  32 A and/or float tools  34 A needed for drilling the well, are suspended from a drilling platform  24 A of a rig  26 A. On rig  26 A are provided equipment (not shown) for setting the rotational alignment of the drill string  20 A, to control the depth position of the drill string  20 A, and to provided fluids such as drilling mud, water, cement, or other fluids used in the drilling of wells into the borehole  10 A or down the hollow central portion  28 A (shown in  FIG. 43 ) of the drill string  20 A to power the drill motor to turn the drill bit  32 A. 
     Referring now to  FIG. 43 , there is shown a float sub  34 A of the present invention, in this embodiment being integrally formed within a section of tubing  20 A within the bent sub portion and thus placed into the drill string  20 A at the time the drill string  20 A was inserted into the earth. Float sub  34 A generally includes an annular body portion  36 A, having a configured central aperture  38 A therethrough in which downhole peripherals such as mule shoe  52 A and valve  42 A may be positioned. The body portion  36 A is preferably configured of a drillable material such as the cement used to secure the annulus between the borehole and the drill string  20 A where the drill string  20 A is used as casing, or of plastic, cast iron, aluminum, or such other easily drillable material such that the body portion, and the attendant mule shoe  52 A and valve  42 A can be easily removed from the casing by drilling them out in position in the drill string  20 A. Central aperture  38 A includes an upper guide portion  44 A, in this embodiment configured as an integral frustoconical surface narrowing from an anti-rotation profile  31 A formed at the upper surface of the float sub body  34 A leading to landing bore  46 A, and terminating in enlarged valve receipt bore  48 A. Landing bore  46 A is a generally right cylindrical bore, having an alignment sleeve  50 A disposed therein within which is provided shoe  52 A for the receipt of a survey tool  60 A (shown positioned above the float sub  34 A in  FIG. 43 ) in an aligned position within the float sub  34 A. As shown in  FIG. 43 , shoe  52 A is generally a tubular member, the upper end of which is received in secured engagement with the inner diameter of sleeve  50 A at the lowermost end thereof in the landing bore  40 A. The upper surface of shoe  52 A is provided with a mule shoe profile  54 A, i.e., the uppermost annular surface  56 A of shoe  52 A facing in an up-bore direction is configured as a plane cut across the tubular profile of the shoe  52 A at an angle to the centerline of the shoe  52 A, such that the perimeter of the upper terminus of the shoe  52 A at mule shoe profile  54 A is an ellipse. Shoe  52 A additionally includes a slot  58 A, extending in a downhole direction from mule shoe profile  54 A, in the wall of the shoe  52 A. It is understood that the mule shoe profile  54 A may include other geometries in addition to an ellipse. 
     Referring still to  FIG. 43 , valve body  62 A is received downhole from shoe  52 A, in valve receipt bore  48 A. Valve body  62 A generally includes a housing  64  having a through-bore  66 A therethrough which extends from the lowermost extension of shoe  52 A to a valve assembly  68 A. Housing  64 A is preferably cast in, threaded into, or otherwise permanently secured within body  34 A before loading the float sub  34 A into the drill string  20 A. Valve assembly  68 A is shown in this embodiment as a “flapper”-type valve, i.e., a valve wherein a cover plate  70 A is connected by a spring-loaded hinge  72 A to the housing  64 A, such that cover plate  70 A is positioned when in a closed position over the opening of bore  66 A at the underside of the housing  64 A to thereby seal the bore from entry of fluids from a location downhole therefrom into the bore  66 A, and thus into the hollow interior region  28 A of the drill string  20 A. However, when fluid is directed down the hollow interior region  28 A of the drill string  20 A, such fluid may pass through the hollow interiors of the sleeve  50 A and mule shoe  52 A, and thus through the through-bore  66 A to provide a sufficient force bearing upon the valve to cause the cover plate  70 A to swing open about the hinge  72 A, thereby allowing such fluids to pass therethrough and thence onwardly down the portion of the drill string  20 A therebelow. The fluid may exit into the wellbore through the mud passages in the bit. In another embodiment, the fluid may pass through the powering passages in the mud-driven drill motor (not shown) before reaching the bit. The configuration of the float sub  34 A shown in  FIG. 43  locates the sleeve  50 A generally co-linearly with the center of drill string  20 A, and thus the receipt of a survey tool therein, as will be described further herein, will position the survey tool in the center of the drill string  20 A. However, there exist survey tools where it would be useful to have the survey tool to one side of the drill string  20 A, therefore, the bore  46 A of the float sub  34 A may be offset to one side or the other (i.e., not co-linear with the drill string  20 A centerline) such that the sleeve  50  will likewise be offset from the centerline of the drill string  20 A. 
     Referring still to  FIG. 43 , a survey tool  60 A is shown within drill string  20 A suspended on a wireline  102 A above (or adjacent to) float sub  34 A. Survey tool  60 A generally includes a hollow, generally cylindrical body  104 A having an outer cylindrical portion  106 A having an inner diameter substantially equal to that of shoe  52 A, and an outer diameter slightly smaller than the inner diameter of the sleeve  50 A within which shoe  52 A is received; an upper cover portion  108 A from which wireline extends from the tool  60 A; and an open lower end  110 A. The lower end  110 A is likewise configured with a mating mule shoe profile  100 A (shown in  FIG. 43A ), cut at the same angle as that of shoe  52 A, to provide a mating elliptical surface to that of the mule shoe profile  54 A on shoe  52 A.  FIG. 43A  shows a side view of the survey tool  60 A having a mating profile  100 A for mating with the mule shoe profile  54 A on the shoe  52 A. 
     To retrieve the survey tool  60 A from the well where the tool  60 A becomes separated from the wireline  102 A, cover portion  108 A may include a fishing neck  112 A thereon for retrieving of the survey tool  60 A with a fishing tool (not shown). In another embodiment, the tool  60 A may be intentionally separated from the wireline  102 A and left in place. In another embodiment still, the tool  60 A may be pre-assembled with shoe  52 A only to be retrieved later by wireline or pipe. The body  104 A further includes a plurality of flow passages  116 A extending therethrough which enable fluids to flow between the hollow portion  28 A of the drill string  20 A and the interior volume  118 A of the body  104 A. A plurality of stabilizers  120 A are located on the outer surface of body  104 A help center the survey tool  100 A in the drill string  20 A as it is lowered from the surface through hollow portion  28 A. 
     Within survey tool  60 A and connected to wireline  102 A passing through upper cover portion  108 A is a diagnostic apparatus  114 A. In the embodiment shown, this diagnostic apparatus  114 A is a geosensor and sender combination which, in conjunction with a computer and computer program therein, is able to determine orientation of the borehole  10 A in the earth, and thus is needed to ensure that the borehole  10 A is progressing in the desired direction once the rotational position of the survey tool  60 A is known. 
     Referring now to  FIG. 44 , the receipt of survey tool  60 A in shoe  52 A is shown. Survey tool  60 A is lowered down the hollow portion  28 A of drill string  20 A on wireline  102 A such that lower end  110 A thereof is received within landing bore  46 A of float tool  34 A. Where survey tool  60 A is axially misaligned with landing bore  46 A, i.e., is offset to one side of the drill string  20 A, the lower end thereof will engage the tapered surface  44 A on alignment bore  46 A and be guided to the opening of sleeve  50 A. Thence survey tool  60 A is further lowered, such that the lower end thereof enters sleeve  50 A and the mating mule shoe profile  100 A on the lower end  110 A of survey tool  60 A will contact the mule shoe profile  54 A on shoe  52 A. Where the rotational alignment of the two profiles is not such that the plane of their elliptical faces is not parallel, further lowering of the survey tool  60 A will cause the end  110 A of survey tool  60 A to slide upon the mule shoe profile  54 A of shoe  52 A, simultaneously causing the survey tool  60 A to rotate until the survey tool  60 A is fully received against profile  54 A such that the planar elliptical faces of each of profiles  54 A,  100 A are in parallel contact. 
     In the preferred embodiment hereof, the drill shoe includes a cutting apparatus which may be a traditional rock bit, a drill motor, or the like, preferably configured to be drilled through by a subsequent, smaller drill shoe passed down the casing. Alternatively, the drill shoe may include a jet section having a plurality of fluid jets extending from a central bore thereof (not shown) to the exterior thereof in a known circumferential position. Preferably, as is known in the art, the fluid jets may be selectively controlled to enable jetting into the formation for removal of formation materials and thereby create a deviation in the direction of the borehole direction. Thus, the drill string (or drill motor) may be rotated to drill ahead or the jets may be oriented by rotational positioning and selection thereof to drill directionally. The drill shoe also preferably includes a plurality of mud passages therethrough, through which drilling fluids may pass to lubricate or cool the cutting surface and enable the removal of cuttings from the borehole as the drilling fluid is recirculated to the earth&#39;s surface. 
     The orientation or rotational alignment of the mule shoe profile  54 A, being known prior to the placement of the survey tool  60 A therein, enables multiple functions to be accomplished downhole with a high degree of reliability. In one aspect, the survey tool  60 A may be a gyroscope, which is adapted to acquire information relating to wellbore position. The position information is communicated to the surface via the wireline  120 A. Particularly, surface components or controllers may receive information relating to the orientation of the gyro and the rotational position of the casing, including the bent sub. In turn, the position of the casing or the bent sub may be changed by rotating the casing at the surface to provide the desired orientation or position. Thereafter, the gyro may be removed via the wireline  120 A, or if necessary via a fishing tool. After orientation, drilling or jetting through selective ports of the jet portion of the drill shoe may be undertaken to establish a new or desired direction of the borehole. The new direction of the borehole may be determined and verified by landing the gyro on the muleshoe profile  54 A. Any additional directional modification may be performed, as needed, according to the method described above. 
     Alternatively, a measure-while-drilling tool (“MWD tool”) or LWD tool  600 A having a survey tool  660 A may be used to determine and steer the drill shoe (located below  620 A) as drilling progresses, as illustrated in  FIG. 47 . Many types of sensors may be utilized, including magnetic, gravity, gyro sensors and any combination thereof. Additionally, many types of telemetry including mud-pulse, electromagnetic, acoustic, wireline, fiberoptic, wired casing, and any combination thereof. Any combination of sensors and telemetry may be utilized. The advantage of using the fluid-driven or continuous MWD/LWD tool  600 A is that the drilling may continue with the survey tool  660 A landed on the bore  646 A. The drilling may continue using a drill motor  625 A, wherein the casing  605 A need not be rotated as the drill shoe  620 A is then mud flow powered, or a traditional rock bit is used and the casing  605 A may be turned to supply the formation-bit motion and cutting power. The MWD/LWD tool  600 A may be equipped with a mud pulse telemetry component  610 A to send information such as inclination and azimuth of the wellbore back to the surface. In one aspect, mud pulse telemetry  610 A includes manipulating fluid flow through holes  616 A by varying the total flow area of the holes  616 A such that pressure pulses are perceivable at the surface. In this respect, mud pulse telemetry  610 A is a way to communicate information from downhole to surface. In this manner, the direction of the borehole may be checked with or without ongoing drilling operation in the borehole. It must be noted that information may also be sent back to the surface using other methods known to a person of ordinary skill in the art, for example electromagnetic communication. 
     Referring to  FIGS. 42-44 , the float sub  34 A and survey tool  60 A, in combination, enable simultaneous survey and drilling operations, as well as other simultaneous operations which may be useful in the downhole location. Specifically, survey tool  60 A may be securely located in float sub  34 A, while drilling mud, water, cement, or other liquids are flowed therethrough. Specifically, where fluids are flowed from the surface location and down hollow portion  28 A of drill string  20 A, such fluid, upon reaching survey tool, bears upon survey tool and tends to maintain it against shoe  52 A, and such fluid likewise flows through flow passages  116 A to the hollow interior  118 A of the survey tool. Thence, such fluids flow through the hollow bore of shoe  52 A and bore  66 A in the valve body  64 A, such that they bear upon and open or maintain open the valve cover plate  70 A, and thus continue flowing down the remainder of the drill string  20 A to locations such as the drill or mud motor and mud passages in the drill bit (not shown) and thence up the annulus between the drill string  20 A and the borehole  10 A. If the flow of fluid down the drill string  20 A is interrupted or stopped or the pressure below the valve  68 A exceeds the pressure of the mud at the valve  68 A, the fluid in annulus will reflow back up the drill string  20 A unless blocked. Such reflow would dislodge the survey tool from the shoe  52 A, and may damage survey tool  60 A. However, as cover plate  70 A on valve body  42 A is spring-loaded by hinge  72 A to be biased in a closed direction, where the pressure above the valve approaches the back pressure exerted against the valve, the cover plate  70 A will close over bore  66 A. Further increases in back pressure caused by the fluid in the annulus  10 A will only increase this closing force, thereby sealing off bore  66 A and preventing further backflow or reflow of the fluids up the drill string  20 A. Although the valve  68 A has been described as a flapper-type valve, other valves such as check valves, poppet valves, auto-fill valves, or differential valves, the operation and construction of which are well known to those skilled in the art, may be substituted for the flapper valve without deviating from the scope of the invention. 
     Referring now to  FIGS. 45 and 46 , an alternative survey tool configuration is shown. In this embodiment, survey tool  200 A is in all cases structured similar to survey tool  60 A, except mule shoe profile of the survey tool  60 A is replaced such that open lower end  202 A of survey tool  200 A is generally a right circular cylinder, and an alignment lug  204 A is provided on the outer surface of tool  200 A. As this tool is lowered into the float sub  34 A from the position of  FIG. 45  to the fully-landed position of the survey tool  200 A of  FIG. 46 , lug  204 A will engage the mule shoe profile  54 A of shoe  52 A and slide therealong, thereby rotating the survey tool  200 A, as shown by the 90-degree turn of the tool  200 A between  FIG. 45  and  FIG. 46 , as tool  200 A is further loaded into shoe  52 A, until lug  204 A is aligned with slot  58 A, whence further lowering of tool  200 A causes lug  204 A to travel down to the base of slot  58 A at which time tool  200 A is fully engaged and aligned in shoe  52 A. The survey tool  204 A is smaller in diameter than survey tool  60 A, as it must slide into shoe  52 A whereas survey tool  60  rests upon the upper surface of the shoe  52 A. Survey tool  200 A is in all other respects identical to survey tool  60 A, and the operation of the tool  200 A in conjunction with mudflow therethrough is identical to that of survey tool  60 A. 
     As with survey tool  60 A, the orientation or rotational alignment of the survey tool  200 A is known with respect to the position of the bent sub, the drill shoe, or the jet section, as the orientation of the slot  58 A is known with respect to these portions of the drill string when they are assembled together before entering the borehole. Thus, survey tool  200 A may comprise a gyro, and signals therefrom indicative of the direction in which the borehole is progressing and the alignment or orientation of the drill shoe components may be sent on wireline  120 A to the surface to enable repositioning of the drill shoe components if needed, as was accomplished with respect to the survey tool  60 A. Likewise, an MWD/LWD tool could be landed in the float sub  34 A and utilize the alignment provided by the slot  58 A to continue drilling and steering using the MWD/LWD. While the MWD/LWD tool is landed on the float sub  34 A, the MWD/LWD tool can communicate the survey information to the surface via mud pulse telemetry, thereby eliminating the need to remove the survey tool to further drill the borehole. 
     The float sub  34 A of the present invention provides multiple useful downhole features when provided in a drill string  20 A. First, the position of the shoe  52 A relative to the drill bit is noted prior to placement of the float sub  34 A down the borehole, thereby enabling the use of data retrieved from or calculated by the survey tool to have a meaningful relation to the face being drilled. Additionally, the shoe  52 A enables a known rotational alignment of the well survey tool  60 A,  200 A, when seated in the float sub  34 A, which likewise enables meaningful data retrieval and generation for bit heading. Further, the use of an aligning element in combination with flow through the survey tool  60 A,  200 A housing, allows the drilling mud or other fluid flowing down the drill string  20 A to be used to ensure that the survey tool  60 A,  200 A remains fully seated and thus properly oriented, as surveying is occurring, and likewise allows survey to occur when fluids are flowing through the system and thus as drilling is ongoing. 
     In each instance, after surveying is completed and well production need be initiated, the float sub  34 A components must be removed or otherwise rendered non-impeding to the production of fluid from the well. Because the survey tool  60 A  200 A is merely sitting in the float sub  34 A, it may be easily removed from the float sub  34 A such as by extending a fishing tool (not shown) and engaging fishing neck  112 A to pull the survey tool from the drill string  20 A, or if the wireline  102 A is sufficiently strong, the survey tool may be pulled up with the wire  102 A. In another aspect, the survey tool  60 A,  200 A may be latched in the float sub  34 A with a collet assembly, secured in place with shear screws or other methods known to a person of ordinary skill whereby the survey tool may be retrieved with relative ease. 
     Once the survey tool is removed, the float sub  34 A is used to enable cementing of the casing  22 A comprising the drill string  30 A in place in the borehole, to case the borehole. Specifically, cement is flowed down the interior  28 A of the casing  20 A, and through the float sub  34 A (as flowed drilling fluids), and thence out the mud passages in the drill shoe or other cementing passages provided therefore and into the annular space between the drill string  20 A and the borehole  10 A and  16 A. This cement may need to cure in place without backing up through the interior of the drill string before hardening. Therefore, when the cementing fluid is no longer flowed down the drill string and a secondary, lighter liquid is poured into the drill string immediately behind the cement whereby the pressure in the drill string will be less than that in the annulus between the drill string  20 A and the borehole  10 A and  16 A, the valve assembly  68 A will close over the opening of bore  66 A at the underside of the housing  64 A to seal the bore from entry of cement back into the hollow interior region  28 A of the drill string  20 A. In another aspect, one or more isolation subs (not shown) may be positioned above or below the float shoe  34 A to prevent leakage of cement back up the hollow region  28 A if cement leaks past valve assembly  68 A. 
     After the cement is cured, the float sub  34 A is then removed, typically by directing a drill, mill, or cutter down the drill string  20 A hollow portion  28 A from the surface, and physically cutting or drilling through the shoe, housing, and valve assembly. The drill, mill, or cutter will readily drill through the cement or plasticbased components of the float sub, as well as any metal portion, into small pieces which may be recovered, in part, by being carried to the surface in drilling mud. Additionally, there is a benefit to having as much of the componentry as practicable, such as valve body  48 A, etc. constructed of a material which is easily ground up or drilled through yet has sufficient strength to retain its shape under pressure. Once the float sub is removed, production tubing or other production elements can easily be passed through the drill string  20 A past the former location of the float sub  34 A. In instances where the borehole has not yet reached its ultimate depth, an additional casing to be cemented in place having a drilling bit and a drill motor operatively attached thereto may be used to drill through the float sub  34 A and the drill motor at the bottom of the drill shoe to continue drilling further into the earth. 
     Although the invention has been described with respect to its use in a situation where the drill string  20 A is to be used, in situ, as casing, the invention is as applicable to situations where a well is separately cased with tubing. In such an embodiment, a section of the casing may be provided with float sub  34 A therein in a fixed longitudinal and angular alignment, and the distance from the float sub  34 A to other locations of interest such as the end of the lowestmost casing in the stack noted. Thus, the float sub  34 A may be used to enable survey tool alignment and positioning in casing, although drilling may not be simultaneously occurring. 
     Although the float sub  34 A has been described in terms of a landing platform for receiving and orienting a survey tool, float sub  34 A may be modified to include additional features, for example a latching collar or other receptacle formed therein to which a latching system such as a float collar or a cementing tool may be secured. Likewise, the float sub may be configured to include a stage tool, whereby a blocking member such as a ball (not shown) may be positioned to block the bore  66 A, such that cement may be directed through the stage tool portion thereof (not shown). 
     In another aspect shown in  FIGS. 48-52 , the present invention provides a survey tool assembly  900  for use while directionally drilling with casing.  FIG. 48  shows a casing  910  having a drill bit  915  and a cementing valve  920  disposed at a lower portion thereof. In one embodiment, a portion of the casing  910  may be manufactured from a non-magnetic casing. The drill bit  915  may include one or more fluid deflectors (bit nozzles)  925  angled in the direction of desired trajectory. The casing  910  may also include a receiving socket  930  for engagement with the survey tool assembly  900 . Preferably, the receiving socket  930  is aligned or indexed with the fluid deflectors (bit nozzles)  925  to facilitate orientation of the survey tool assembly  900 . 
     The survey tool assembly  900  may include survey tools such as a MWD tool  935  and a gyro  936 . In one embodiment, the survey tools  935 ,  936  are disposed in the body  940  of the survey tool assembly  900  using one or more centralizers  942 . A mud pulser  945  may be used to transmit information from the survey tools  935 ,  936  to the surface. The body  940  has a retrieving latch  950  disposed at one end, and an alignment key  955  disposed at another end. The alignment key  955  is adapted to engage the receiving socket  930  in a manner that orients the survey tool assembly  900  with the fluid deflectors (bit nozzles)  925 . One or more seals  908  may be used to prevent fluid leakage between the survey tool assembly  900  and the casing  910 . Additionally, spring bow centralizers  960  may be disposed on the outer portion of the body  940  to centralize the survey tool assembly  900  in the casing  910 . 
     Many survey tools are actuated by fluid flow. To this end, the survey tool assembly  900  includes a fluid inlet channel  965  to allow fluid to flow into the body  940  to actuate the MWD tool  935  and the gyro  936 . However, many survey tools operate in a fluid flow range that is often below what is necessary for other operations, for example, drilling operation. Consequently, the survey tool must be retrieved prior to the subsequent, higher flow rate operation. The process of repeatedly retrieving and deploying the survey tools is time consuming and expensive. To this end, the survey tool assembly  900  according to aspects of the present invention also includes a bypass valve  970  to allow the subsequent, higher flow rate operation to be performed without retrieving the survey tool assembly  900 . 
     In one embodiment, the bypass valve  970  is disposed at a portion of the body  940  that is below the survey tools  935 ,  936 . The bypass valve  970  is initially biased in the closed position by a biasing member  975 , as illustrated in  FIG. 48 . An exemplary biasing member  975  includes a spring. When the bypass valve  970  is closed, fluid in the casing  910  can only flow into the body  940  of the survey tool assembly  900  through the inlet channel  965 , as illustrated in  FIG. 51 . It must be noted that other types of bypass devices known to a person of ordinary skill in the art are contemplated within aspects of the present invention, for example, a fix orifice bypass. 
     The bypass valve  970  may be opened by providing a higher flow rate. Specifically, the bypass valve  970  opens when the flow rate in the casing  910  overcomes the directional force of the biasing member  975 . Once opened, some of the fluid in the casing  910  may be directed through the bypass valve  970  instead of the inlet channel  965 , as illustrated in  FIG. 52 . In this manner, a higher flow rate may be supplied to perform the subsequent, higher flow rate operation. 
     In operation, the survey tool assembly  900  is assembled inside the casing  910  and is lowered into the wellbore together with the casing  910 . Particularly, the alignment key  955  is situated in the receiving socket  930  to orient the survey tool assembly  900  with the fluid deflectors  925 , as illustrated in  FIG. 49 . A lower fluid flow rate is supplied to operate the survey tools  935 ,  936 . The lower flow rate is insufficient to overcome the spring  975  of valve  970 , but is sufficient to open the cementing valve  920 , as shown in  FIGS. 49 and 51 . It must be noted that the lower flow rate may also be sufficient to operate the drill bit  915  at a slower rate. Information collected by the survey tools  935 ,  936  may be transmitted back to the surface by the mud pulser  945 . 
     The bypass valve  970  is opened when the directional force of the spring is overcome by a higher flow rate. After the bypass valve  970  is opened, fluid flow through the survey tool assembly  900  may occur through the inlet channel  965  and the bypass valve  970 , as illustrated in  FIGS. 50 and 52 . The higher flow rate may operate the drill bit  915  at a faster rate and provide more fluid flow through the fluid deflectors (bit nozzles)  925 , thereby generating a more effective directional control. To collect survey information, the fluid flow may be decreased to close the bypass valve  970  and allow the operation of the survey tools  935 ,  936 . Information collected by the survey tools  935 ,  936  may be transmitted back to the surface via mud-pulse telemetry using the mud pulser  945 . This process of surveying and drilling may be repeated as desired. In this respect, the survey tools  935 ,  936  do not need to be retrieved and reconveyed downhole as drilling progresses, thereby saving time and cost of the operation. After drilling is complete, the survey tool assembly  900  may be retrieved by any manner known to a person of ordinary skill in the art. Preferably, the survey tool assembly  900  is retrieved by latching a wireline to the retrieving latch  950 . In this manner, the survey tool assembly  900  may be reused in the next drilling operation. 
     Any of the above-mentioned downhole electromechanical devices such as drilling tools, directional tools, sensor package, cementing gear, and the like may be controlled or actuated by string rotation; mud pump cycling, wireline electric signal, wired casing signal, or combinations thereof. Controlling and/or actuating by string rotation may involve using a number of start/stop cycles and/or varying rpm. Controlling and/or actuating by mud pump cycling may involve using a number of start/stops of the flow rate and/or varying the flow rate. 
     In one embodiment, the present invention provides a method for directing a trajectory of a lined wellbore comprising providing a drilling assembly comprising a wellbore lining conduit and an earth removal member; directionally biasing the drilling assembly while operating the earth removal member and lowering the wellbore lining conduit into the earth; and leaving the wellbore lining conduit in a wellbore created by the biasing, operating and lowering. In one aspect, directionally biasing the drilling assembly comprises urging fluid through a non-axis-symmetric orifice arrangement of the drilling assembly. In one embodiment, the non-axis-symmetric orifice arrangement is disposed on the earth removal member. In another aspect, directionally biasing comprises urging the drilling assembly against a non-axis-symmetric pad arrangement included thereon. In one embodiment, the non-axisymmetric pad arrangement is disposed on the wellbore lining conduit. 
     In an additional embodiment, the present invention provides a method for directing a trajectory of a lined wellbore comprising providing a drilling assembly comprising a wellbore lining conduit and an earth removal member; directionally biasing the drilling assembly while operating the earth removal member and lowering the wellbore lining conduit into the earth; and leaving the wellbore lining conduit in a wellbore created by the biasing, operating and lowering. In one embodiment, the method further comprises a second wellbore lining conduit having a portion disposed substantially co-axially within the wellbore lining conduit. 
     In an additional embodiment, the present invention provides a method for directing a trajectory of a lined wellbore comprising providing a drilling assembly comprising a wellbore lining conduit and an earth removal member; directionally biasing the drilling assembly while operating the earth removal member and lowering the wellbore lining conduit into the earth; and leaving the wellbore lining conduit in a wellbore created by the biasing, operating and lowering, the drilling assembly further comprising a motor having a rotating shaft, the rotating shaft having a fluid passage therethrough. In an additional embodiment, the present invention provides a method for directing a trajectory of a lined wellbore comprising providing a drilling assembly comprising a wellbore lining conduit and an earth removal member; directionally biasing the drilling assembly while operating the earth removal member and lowering the wellbore lining conduit into the earth; and leaving the wellbore lining conduit in a wellbore created by the biasing, operating and lowering, wherein a latch member operatively connects the earth removal member to the wellbore lining conduit. 
     In one embodiment, the present invention provides an apparatus for drilling a well, comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; and a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft. In one aspect, the divert assembly comprises a closing sleeve having one or more ports, the closing sleeve disposed in the shaft. In another aspect, the divert assembly comprises a rupture disk disposed to block fluid flow to the passageway in the shaft. 
     Another embodiment of the present invention provides an apparatus for drilling a well, comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; and a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft. In one aspect, the motor operating system comprises a hydraulic system, while in another aspect, the motor operating system comprises a system selected from a turbine system and a stator system. 
     An additional embodiment of the present invention provides an apparatus for drilling a well, comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; and a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; and a drill shoe rotatably connectable to a casing, the drill shoe comprising a rotatable drill face and a spindle connected to the shaft. In one aspect, the drill shoe includes a fluid connection to the passageway in the shaft. In another aspect, the drill shoe includes a shut-off mechanism for stopping fluid flow through the fluid connection. 
     In one embodiment, the present invention provides an apparatus for drilling a well, comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; and a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; and a casing latch attached to the motor system housing, the casing latch connected to releasably secure the apparatus to an internal surface of a casing. In one aspect, the casing comprises a nozzle biased in a direction for directionally drilling the casing. In another aspect, the casing comprises a stabilizer proximate to a midpoint of the casing for directionally drilling the casing. In yet another aspect, the casing latch includes a fluid passage connected to the passageway in the shaft. In yet another aspect, the apparatus further comprises a guide assembly connected to the casing latch, the guide assembly having a cone portion and a tubular portion. In one aspect, the guide assembly includes one or more seats for receiving a device selected from an inter string and an orientation device. 
     Another embodiment of the present invention provides an apparatus for drilling a well, comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; and a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft, wherein the motor system housing includes an enlargement portion for expanding a casing size. 
     An additional embodiment of the present invention provides an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; and a drill face operably connected to shaft of the motor system. In one aspect, the apparatus further comprises a latch for releasably latching onto the casing, the latch fixedly connected to the motor system. 
     An additional embodiment of the present invention provides an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; and a drill face operably connected to shaft of the motor system, wherein the divert assembly comprises a closing sleeve having one or more ports, the closing sleeve disposed in the shaft. A further additional embodiment of the present invention provides an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; and a drill face operably connected to shaft of the motor system, wherein the divert assembly comprises a rupture disk disposed to block fluid flow to the passageway in the shaft. 
     An additional embodiment of the present invention provides an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; and a drill face operably connected to shaft of the motor system, wherein the motor operating system comprises a hydraulic system. A further additional embodiment provides an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; and a drill face operably connected to shaft of the motor system, wherein the motor operating system comprises a system selected from a turbine system and a stator system. 
     In one embodiment, the present invention provides an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; a drill face operably connected to shaft of the motor system; and a drill shoe rotatably connectable to the casing, the drill shoe having the drill face and a spindle connected to the shaft. In one aspect, the drill shoe includes a fluid connection to the passageway in the shaft. In a further aspect, the drill shoe includes a shut off mechanism for stopping fluid flow through the fluid connection. 
     In one embodiment, the present invention provides an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; a drill face operably connected to shaft of the motor system; and a casing latch attached to the motor system housing, the casing latch connected to releasably secure the apparatus to an internal surface of the casing. In one aspect, the casing latch includes a fluid passage connected to the passageway in the shaft. 
     In another embodiment, the present invention provides an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; a drill face operably connected to shaft of the motor system; a casing latch attached to the motor system housing, the casing latch connected to releasably secure the apparatus to an internal surface of the casing; and a guide assembly connected to the casing latch, the guide assembly having a cone portion and a tubular portion. In one aspect, the guide assembly includes one or more seats for receiving a device selected from an inter string and an orientation device. 
     The present invention provides in yet another embodiment an apparatus for drilling with casing, comprising a casing; a motor system retrievably disposed in the casing, the motor system comprising a motor operating system disposed in a motor system housing; a shaft operatively connected to the motor operating system, the shaft having a passageway; a divert assembly disposed to direct fluid flow selectively to the motor operating system and the passageway in the shaft; a drill face operably connected to shaft of the motor system, wherein the motor system housing includes an enlargement portion for expanding a casing size. 
     Another embodiment of the present invention includes a method for drilling and completing a well, comprising pumping drill mud to a motor system disposed in a casing; rotating a drill face connected to the motor system; diverting fluid flow to a passageway through the motor system; and pumping cement through the passageway to the drill face. In one aspect, the method further comprises releasably latching the motor system to the casing utilizing a casing latch. 
     A further embodiment of the present invention includes a method for drilling and completing a well, comprising pumping drill mud to a motor system disposed in a casing; rotating a drill face connected to the motor system; diverting fluid flow to a passageway through the motor system; and pumping cement through the passageway to the drill face, wherein the drill mud and the cement are pumped utilizing an inter string. In another embodiment, the present invention includes Another embodiment of the present invention includes a method for drilling and completing a well, comprising pumping drill mud to a motor system disposed in a casing; rotating a drill face connected to the motor system; diverting fluid flow to a passageway through the motor system; pumping cement through the passageway to the drill face; and retrieving the motor system from the casing. 
     Another embodiment of the present invention includes a method for drilling and completing a well, comprising pumping drill mud to a motor system disposed in a casing; rotating a drill face connected to the motor system; diverting fluid flow to a passageway through the motor system; pumping cement through the passageway to the drill face; and expanding the casing utilizing an enlarged portion of a housing for the motor system. 
     In a further embodiment, the present invention includes a method of initiating and continuing a path of a wellbore, comprising providing a first casing having a first earth removal member operatively disposed at a lower end thereof; penetrating a formation with the first casing to form the wellbore; selectively altering a trajectory of the wellbore while penetrating the formation of the first casing; flowing drilling fluid to a motor system disposed in a second casing, the second casing being releasably attached to an inner diameter of the first casing and having a second earth removal member; rotating the second earth removal member with the motor system; and selectively altering the trajectory of the second casing as it continues into the formation. In one aspect, the trajectory of the second casing is altered more than the trajectory of the first casing. 
     The present invention further includes in one embodiment a method of altering a path of a casing into a formation, comprising providing an outer casing with a deflector releasably attached to its lower end; penetrating the formation with the deflector; releasing the releasable attachment; deflecting the path of the outer casing in the formation by moving the casing string along the deflector; releasing an inner casing from a releasable attachment to the outer casing; and flowing drilling fluid to a motor system disposed within the inner casing to rotate an earth removal member operatively attached to the motor system while altering a trajectory of the inner casing drilling into the formation. In another embodiment, the present invention further includes an apparatus for deflecting a wellbore, comprising an outer casing with a member for deflecting the casing string preferentially in a direction; a first earth removal member operatively connected to a lower end of the outer casing; and an inner casing having a motor operating system disposed therein disposed within the outer casing and operatively attached thereto. 
     In a yet further embodiment, the present invention includes a method for preferentially directing a path of a casing to form a wellbore, comprising providing a second casing concentrically disposed within a first casing having a biasing member, the second casing having a motor system releasably attached therein; jetting the first casing having an earth removal member operatively connected thereto into a formation to a first depth while selectively altering the trajectory of the wellbore using the biasing member; releasing a releasable attachment between the first and second casing; providing drilling fluid to the motor system; and selectively altering a trajectory of the second casing while rotating an earth removal member operatively connected to a lower end of the motor system as the second casing continues into the formation. In one aspect, the biasing member includes a preferential jet for directing fluid flow asymmetrically through the first casing while jetting. In another aspect, the biasing member includes a stabilizing member disposed proximate to a midpoint of the first casing. 
     In an embodiment, the present invention includes a method for preferentially directing a path of a casing to form a wellbore, comprising providing a second casing concentrically disposed within a first casing having a biasing member, the second casing having a motor system releasably attached therein; jetting the first casing having an earth removal member operatively connected thereto into a formation to a first depth while selectively altering the trajectory of the wellbore using the biasing member; releasing a releasable attachment between the first and second casing; providing drilling fluid to the motor system; selectively altering a trajectory of the second casing while rotating an earth removal member operatively connected to a lower end of the motor system as the second casing continues into the formation; and diverting fluid flow to a passageway through the motor system. In one aspect, the method further comprises flowing a physically alterable bonding material through the passageway to the earth removal member. 
     An additional embodiment of the present invention includes a method for preferentially directing a path of a casing to form a wellbore, comprising providing a second casing concentrically disposed within a first casing having a biasing member, the second casing having a motor system releasably attached therein; jetting the first casing having an earth removal member operatively connected thereto into a formation to a first depth while selectively altering the trajectory of the wellbore using the biasing member; releasing a releasable attachment between the first and second casing; providing drilling fluid to the motor system; selectively altering a trajectory of the second casing while rotating an earth removal member operatively connected to a lower end of the motor system as the second casing continues into the formation; drilling the second casing to a second depth; and expanding the second casing. In one aspect, expanding the second casing is accomplished by retrieving the motor system from the second casing. 
     In another embodiment, the present invention includes a method for preferentially directing a path of a casing to form a wellbore, comprising providing a second casing concentrically disposed within a first casing having a biasing member, the second casing having a motor system releasably attached therein; jetting the first casing having an earth removal member operatively connected thereto into a formation to a first depth while selectively altering the trajectory of the wellbore using the biasing member; releasing a releasable attachment between the first and second casing; providing drilling fluid to the motor system; selectively altering a trajectory of the second casing while rotating an earth removal member operatively connected to a lower end of the motor system as the second casing continues into the formation; and retrieving the motor system from the second casing. 
     The present invention further includes, in one embodiment, a method for preferentially directing a path of a casing to form a wellbore, comprising providing a second casing concentrically disposed within a first casing having a biasing member, the second casing having a motor system releasably attached therein; jetting the first casing having an earth removal member operatively connected thereto into a formation to a first depth while selectively altering the trajectory of the wellbore using the biasing member; releasing a releasable attachment between the first and second casing; providing drilling fluid to the motor system; selectively altering a trajectory of the second casing while rotating an earth removal member operatively connected to a lower end of the motor system as the second casing continues into the formation; and selectively introducing a surveying tool into the motor operating system to selectively measure the trajectory of the wellbore. In one aspect, the surveying tool selectively measures the trajectory of the wellbore while drilling with the first or second casing. 
     In an embodiment, the present invention includes a method for preferentially directing a path of a casing to form a wellbore, comprising providing a second casing concentrically disposed within a first casing having a biasing member, the second casing having a motor system releasably attached therein; jetting the first casing having an earth removal member operatively connected thereto into a formation to a first depth while selectively altering the trajectory of the wellbore using the biasing member; releasing a releasable attachment between the first and second casing; providing drilling fluid to the motor system; and selectively altering a trajectory of the second casing while rotating an earth removal member operatively connected to a lower end of the motor system as the second casing continues into the formation; and measuring a trajectory of the wellbore while drilling with the first or second casing. 
     An embodiment of the present invention includes an apparatus for deflecting a wellbore, comprising a casing having upper and lower portions and an earth removal member operatively attached to its lower end; and at least one hole-opening blade disposed on the upper portion of the casing string for gravitationally bending the casing to alter a trajectory of the wellbore. The hole-opening blade comprises a concentric stabilizer in one aspect. In another aspect, the hole-opening blade is an eccentric stabilizer. An additional embodiment of the present invention includes an apparatus for deflecting a wellbore, comprising a casing having upper and lower portions and an earth removal member operatively attached to its lower end; at least one hole-opening blade disposed on the upper portion of the casing string for gravitationally bending the casing to alter a trajectory of the wellbore; and at least one angled perforation in the earth removal member for further altering the trajectory of the wellbore through asymmetric fluid flow through the perforation. 
     An embodiment of the present invention includes a method for deflecting a wellbore while drilling with casing, comprising providing a casing with a drilling member at a lower end thereof; penetrating a formation with the casing while selectively altering a trajectory of the casing; pumping drilling fluid to a motor system disposed in an additional casing disposed within the casing; rotating the additional casing with the motor system, the motor system having an earth removal member operatively attached to its lower end; and selectively altering a direction of additional casing to deflect the wellbore at a further trajectory. An additional embodiment includes a method of deflecting a wellbore while drilling with casing, comprising providing a casing with a drilling member at a lower end thereof; providing a deflecting member releasably attached to the drilling member; anchoring the deflecting member in the wellbore at a predetermined depth; and urging the drilling member along the deflector, thereby altering the direction of the wellbore. 
     A further embodiment of the present invention includes a method of deflecting a wellbore while drilling with casing, comprising providing a casing with a drilling member at a lower end thereof, the drilling member having at least one fluid path extending therefrom, the fluid path directed away from a longitudinal centerline of the string; and pumping fluid through the fluid path, thereby altering the direction of the wellbore. A further embodiment includes a method of deflecting a wellbore while drilling with casing, comprising forming a first, larger diameter wellbore; providing a second, lower, smaller diameter wellbore; and slanting a casing string to direct the lower end thereof away from the centerline of the wellbore, thereby altering the direction of the wellbore. 
     In another embodiment, the present invention includes a method of initiating and continuing a path of a wellbore, comprising providing a casing string and a cutting apparatus disposed at a lower portion of the casing string; penetrating a formation with the casing string to form the wellbore; and selectively altering the trajectory of the casing string as it continues into the formation. In one aspect, selectively altering the trajectory of the casing string comprises selectively jetting fluid to create an asymmetric flow pattern through a lower portion of the cutting apparatus. In another aspect, selectively altering the trajectory of the casing string comprises selectively diverting fluid flow out of a portion of the casing string. In one embodiment, selectively diverting fluid flow forms a profile in a portion of the formation through which the casing string continues. 
     An embodiment of the present invention includes a method of initiating and continuing a path of a wellbore, comprising providing a casing string and a cutting apparatus disposed at a lower portion of the casing string; penetrating a formation with the casing string to form the wellbore; and selectively altering the trajectory of the casing string as it continues into the formation, wherein selectively altering the trajectory of the casing string comprises laterally moving the casing string through an enlarged inner diameter of an upper portion of the wellbore. Another embodiment includes the present invention includes a method of initiating and continuing a path of a wellbore, comprising providing a casing string and a cutting apparatus disposed at a lower portion of the casing string; penetrating a formation with the casing string to form the wellbore; selectively altering the trajectory of the casing string as it continues into the formation; and surveying the path of the wellbore while selectively altering the trajectory of the casing string. 
     A further embodiment provides the present invention includes a method of initiating and continuing a path of a wellbore, comprising providing a casing string and a cutting apparatus disposed at a lower portion of the casing string; penetrating a formation with the casing string to form the wellbore; selectively altering the trajectory of the casing string as it continues into the formation; and introducing at least one additional casing string into the casing string. In an embodiment, the present invention includes a method of initiating and continuing a path of a wellbore, comprising providing a casing string and a cutting apparatus disposed at a lower portion of the casing string; penetrating a formation with the casing string to form the wellbore; and selectively altering the trajectory of the casing string as it continues into the formation, wherein penetrating the formation with the casing includes jetting fluid through at least one nozzle disposed in the cutting apparatus, the at least one nozzle having an extended bore which is adjustable to vary the penetration rate of the casing into the formation. 
     An embodiment of the present invention includes a method of altering a path of a casing string in a formation, comprising providing a casing string with a deflector releasably attached to its lower end; penetrating the formation with the deflector; releasing the releasable attachment; and deflecting the path of the casing string in the formation by moving the casing string along the deflector. In one aspect, the deflector comprises an inclined wedge. 
     An additional embodiment of the present invention includes an apparatus for deflecting a wellbore, comprising a casing string with means for deflecting the casing string preferentially in a direction; and a first cutting apparatus disposed at a lower portion of the casing string. In one embodiment, means for deflecting the casing string preferentially in the direction comprises an inclined wedge releasably attached to a lower portion of the cutting apparatus. In another embodiment, means for deflecting the casing string preferentially in the direction comprises an angled perforation through the lower portion of the casing string for receiving a fluid. In yet another embodiment, means for deflecting the casing string preferentially in the direction further comprises a bent portion in the casing string for deflecting the casing string preferentially in a direction. In another embodiment, means for deflecting the casing string preferentially in the direction comprises a second cutting apparatus larger in diameter than the first cutting apparatus disposed on a portion of the casing string above the first cutting apparatus. 
     An embodiment of the present invention includes an apparatus for deflecting a wellbore, comprising a casing string with means for deflecting the casing string preferentially in a direction; a first cutting apparatus disposed at a lower portion of the casing string; and a landing seat for securing a survey tool therein. In another embodiment, the present invention includes an apparatus for deflecting a wellbore, comprising a casing string with means for deflecting the casing string preferentially in a direction; and a first cutting apparatus disposed at a lower portion of the casing string, wherein the casing string comprises a lower casing string and an upper casing string, and wherein means for deflecting the casing string preferentially in the direction comprises a second cutting apparatus which connects the lower casing string to the upper casing string and is larger in diameter than the second cutting apparatus. 
     Another embodiment of the present invention includes an apparatus for deflecting a wellbore, comprising a casing string with means for deflecting the casing string preferentially in a direction; a first cutting apparatus disposed at a lower portion of the casing string; and a drilling apparatus releasably connected to an inner diameter of the casing string with a second cutting apparatus disposed on the drilling apparatus below the releasable connection. In one aspect, the second cutting apparatus comprises a cutting structure disposed on a portion facing the releasable connection. 
     An embodiment of the present invention includes an apparatus for deflecting a wellbore, comprising a casing string with means for deflecting the casing string preferentially in a direction; and a first cutting apparatus disposed at a lower portion of the casing string, wherein the first cutting apparatus includes at least one nozzle extending therethrough, the at least one nozzle having an extended straight bore extending longitudinally therethrough. 
     An embodiment of the present invention includes an apparatus for deflecting a wellbore, comprising a casing string with means for deflecting the casing string preferentially in a direction; and a first cutting apparatus disposed at a lower portion of the casing string, wherein the first cutting apparatus includes at least one nozzle extending therethrough, the at least one nozzle having an extended straight bore extending longitudinally therethrough. In one embodiment, the at least one nozzle is drillable or made of a soft material such as copper. In another embodiment, the at least one nozzle comprises a thin coating of a hard material, the hard material having a hardness greater than a hardness of a soft material. The hard material may be ceramic or tungsten carbide. The remainder of the at least one nozzle may comprise a soft material such as copper. 
     In another embodiment, the first cutting apparatus includes at least one nozzle extending therethrough, the at least one nozzle being drillable and having a profiled sleeve coating of a hard material. In another embodiment, the first cutting apparatus includes at least one drillable nozzle extending therethrough, the at least one nozzle comprising a hard material having stressed portions therein for increasing breakability of the at least one nozzle when drilled therethrough. 
     In another embodiment, the stressed portions include a plurality of stressed, longitudinal notches in the at least one nozzle. In another embodiment still, a sealing material is disposed in the plurality of stressed notches. 
     In another aspect, the present invention provides a nozzle assembly usable within a tool body while jetting a casing into a formation. The nozzle assembly includes soft, drillable material forming a nozzle retainer and a thin sleeve of a hard material disposed within the nozzle retainer, the hard material forming an longitudinal bore extending past the exit and entry points of a fluid flow path through a hole through the tool body, the hard material having a hardness greater than a hardness of the soft material. In one embodiment, the soft material is copper. In another embodiment, the hard material is ceramic. In another embodiment still, the thin sleeve position is adjustable relative to the nozzle retainer. 
     In another aspect, the present invention provides a method for preferentially directing a path of a casing string to form a wellbore. The method includes jetting the casing string with a cutting structure connected thereto into a formation; and selectively directing the casing string in a direction as the casing string continues into the formation. In one embodiment, selectively directing the casing string in the direction comprises using the casing string to create an annular space in an upper portion of the wellbore and laterally directing an upper portion of the casing string through the annular space. In another embodiment, selectively directing the casing string comprises integrating arcs in the casing string to urge the casing string to form the path in the wellbore while directing fluid asymmetrically out of the cutting structure. In another embodiment, the casing string comprises a tubular body with an inclined wedge attached to its lower portion, and wherein selectively directing the casing string comprises directing the path of the wellbore by obstructing an axial path of the tubular body by the inclined wedge. 
     In another aspect, the present invention provides an apparatus for deflecting a wellbore. The apparatus includes a casing string having upper and lower portions and at least one hole-opening blade disposed on the upper portion of the casing string. In one embodiment, the apparatus also includes a cutting structure disposed on the lower portion of the casing string. In another embodiment, the apparatus further includes a tubular body releasably connected to an inner diameter of the casing string, wherein the tubular body has a cutting apparatus disposed at its lower end comprising a cutting structure located on upper and lower portions thereof. 
     In another aspect, the present invention provides a method for deflecting a wellbore while drilling with casing. The method includes providing a casing string with a drilling member at a lower end thereof; penetrating a formation with the casing string; and selectively altering a direction of the lower end to deflect the wellbore. 
     In another aspect, the present invention provides an assembly for drilling with casing. The assembly includes a casing latch for securing the assembly to a portion of casing; a bit attached to a bottom portion of the assembly; a biasing member for providing the bit with a desired deviation from a center line of the wellbore; and at least one adjustable stabilizer. In one embodiment, the bit is an expandable bit. In another embodiment, the stabilizer has one or more support members adapted to be placed in a first position for running through the portion of casing and a second position for engaging an inner wall of the wellbore. In another embodiment still, the stabilizer is adjustable to at least a third position, wherein an outer diameter of the stabilizer in the third position is less than the outer diameter of the stabilizer in the second position. In yet another embodiment, assembly includes a flexible collar disposed between the bit and the casing latch. In another embodiment still, the biasing member is a bent housing of a downhole motor adapted to drive the bit. In a further embodiment, the assembly includes a measurement tool that is adapted to measure a trajectory of the wellbore and communicate the measured trajectory to the wellbore surface. In another embodiment, the assembly includes at least one additional adjustable stabilizer. The bit may be a pilot bit. The bit may also include an underreamer. 
     In another aspect, the present invention provides a drilling assembly for creating a wellbore, the drilling assembly having a casing portion; a bit assembly disposed on a bottom portion of the drilling assembly, the bit assembly adapted to be expanded from a first diameter to a second diameter; and at least one stabilizer adapted to be adjusted from a first position to at least a second position. In one embodiment, the casing portion is expandable. In another embodiment, the bit assembly comprises an expandable bit. In another embodiment still, the drilling assembly further comprises a biasing member for providing the bit with a desired deviation from a center line of the wellbore. In yet another embodiment, the assembly includes a biasing member for providing the bit assembly with a desired deviation from a center line of the wellbore. In a further embodiment, the assembly includes a downhole drilling motor adapted to rotate the bit. In another embodiment, the assembly includes a flexible collar disposed between the bit assembly and a bottom end of the casing portion. In another embodiment still, the assembly also includes a measurement tool adapted to measure a trajectory of the wellbore and communicate the measured trajectory to the wellbore surface. 
     In one aspect, the present invention provides a method for drilling with casing. The method includes lowering a drilling assembly down a wellbore through casing, wherein the drilling assembly comprises an adjustable stabilizer and one or more drilling elements. The method also includes adjusting one or more support members of the stabilizer to increase a diameter of the stabilizer and operating the drilling assembly to extend a portion of the wellbore below the casing, wherein the extended portion having a diameter greater than an outer diameter of the casing. In one embodiment, the drilling elements may include an expandable bit for expanding the expandable bit to have a larger outer diameter than the casing. 
     In another embodiment, the method may include measuring a trajectory of the wellbore, and in response to the measured trajectory, making one or more adjustments from a surface of the wellbore. The adjustments may involve adjusting the support members of the stabilizer or adjusting a weight applied to the bit. The method may also include sensing a geophysical parameter. 
     In another embodiment, the method may include partially raising the drilling assembly through the casing; advancing the casing into the extended portion of the wellbore; and raising the drilling assembly through the casing to a surface of the wellbore. 
     In another aspect, the present invention provides an apparatus for drilling a wellbore in an earth formation. The apparatus includes a drill string having a longitudinal bore therethrough and a drilling assembly connected at the lower end of the drill string. Preferably, the drilling assembly is selected to be operable to form a borehole and at least in part to be retrievable through the longitudinal bore of the drill string. The apparatus may also include a directional borehole drilling assembly connected to the drill string and including biasing means for applying a force to the drilling assembly to drive it laterally relative to the wellbore and at least one adjustable stabilizer, the adjustable stabilizer retrievable through the longitudinal bore of the drill string. In one embodiment, the adjustable stabilizer is positioned above the biasing means of the directional borehole drilling assembly. In another embodiment, the drilling assembly comprises an expandable bit selected to be operable to form a borehole having a diameter greater than an outer diameter of the drill string and to be retrievable through the longitudinal bore of the drill string. 
     In another aspect, the present invention provides a method for directionally drilling a well with a casing as an elongated tubular drill string and a drilling assembly retrievable from the lower distal end of the drill string without withdrawing the drill string from a wellbore being formed by the drilling assembly. The method includes providing the casing as the drill string; a directional borehole drilling assembly connected to the drill string and including biasing means for applying a force to the drilling assembly to drive it laterally relative to the wellbore; and providing an adjustable stabilizer to support the directional borehole drilling assembly. The method also includes connecting the drilling assembly to the distal end of the drill string and inserting the drill string, the directional borehole drilling assembly, and the drilling assembly into the wellbore. The method further includes adjusting the adjustable stabilizer; forming a wellbore having a diameter greater than the diameter of the drill string; and operating the biasing means to drive the drilling assembly laterally relative to the wellbore. The method further includes removing at least a portion of the drilling assembly from the distal end of the drill string; removing the at least a portion of the drilling assembly out of the wellbore through the drill string without removing the drill string from the wellbore; and leaving the drill string in the wellbore. In one embodiment, the one or more support members is adjusted to change a diameter of the stabilizer. In another embodiment, prior to removing at least a portion of the drilling assembly from the distal end of the drill string, the method further includes partially raising at least a portion of the drilling assembly through the drill string and advancing the drill string within the wellbore. 
     In another aspect, the present invention provides an assembly for drilling with casing. The assembly includes a casing latch for securing the assembly to a portion of casing and a cutting structure attached to a bottom portion of the assembly. The assembly also includes a biasing member for providing the cutting structure with a desired deviation from a centerline of the wellbore, wherein biasing force for providing the cutting structure with the desired deviation is provided substantially by the casing. In one embodiment, the biasing member is an eccentric bias pad disposed on an outer diameter of the casing. The eccentric bias pad may alter the centerline of the casing relative to the borehole centerline in an opposite direction from the side of the casing on which the eccentric bias pad is disposed. In another embodiment, the biasing member comprises a bent motor housing within the casing. The assembly may also include a concentric stabilizer disposed around a lower end of the casing absorbs a majority of the biasing force. In another embodiment still, the casing latch is an orienting latch. In yet another embodiment, the assembly includes at least one of a measuring while drilling tool and a resistivity tool. In yet another embodiment, the cutting structure is expandable. In yet another embodiment, the assembly is retrievable from the casing. 
     In another aspect, the present invention provides a method of drilling with casing. The method includes providing a casing having an assembly releasably connected therein, the assembly comprising an earth removal member at its lower end and a biasing member. The biasing member deflects the earth removal member to a desired angle with respect to the centerline of the wellbore and to place a biasing force on the casing. In one embodiment, the method also includes sensing a geophysical parameter. 
     In another aspect, the present invention provides a method of forming a wellbore using a casing equipped with a cutting apparatus. The method includes positioning an orienting member in the casing, the orienting member having a predetermined orientation relative to the cutting apparatus; and positioning a survey tool with respect to the orienting member, such that an orientation of the survey tool in the casing is known. In one embodiment, the orienting member includes at least one flow aperture therethrough, and the survey tool includes at least one flow aperture therethrough. The orienting member provides an additional downhole functionality such as receiving a cementing tool therein or providing a stage tool integral therewith. In one embodiment, the orienting member may include a slot. In another embodiment, the orienting member may include a mule shoe profile and the survey tool includes a mating mule shoe profile receivable against the mule shoe profile of the landing shoe. The mule shoe profiles of the survey tool and the orienting member provide, upon mating of the mule shoe profiles, alignment between the landing shoe and the survey tool. In another embodiment, the orienting member includes a tubular element having a slot therein. 
     In another embodiment still, the casing comprises a float shoe and the orienting member is disposed in the float shoe. In another embodiment, the survey tool is positioned by landing the survey tool in the orienting member. In another embodiment still, the method further includes acquiring information relating a direction of the cutting apparatus. The method may also include sending the information to a receiving apparatus and steering the cutting apparatus in response to the information acquired. In another embodiment, the cutting apparatus includes a jetting assembly and/or a drilling bit. In yet another embodiment, the method also includes removing the survey tool before drilling is continued. 
     In another aspect, the present invention provides an apparatus for surveying a well wherein a drill string formed of a casing having a cutting apparatus. The apparatus includes an alignment member located in the drill string and a survey tool receivable in said alignment member and alignable thereby to a desired orientation in the drill string. In one embodiment, the alignment member includes a shoe having a profile thereon, the profile indexed rotationally with respect to the circumference of the drill string. The survey tool includes an alignment element interactive with the shoe upon locating of the survey tool in the shoe to provide a known alignment of the survey tool with the drill string. In another embodiment, the survey tool alignment element includes a profile matable with the profile of the alignment member. In yet another embodiment, the alignment member further includes a slot; the survey tool includes a generally cylindrical body having an alignment lug projecting therefrom; and the lug is positionable in the slot when the survey tool is disposed in the alignment member to provide a known orientation of the survey tool with the drill string. 
     In another embodiment still, the survey tool includes a generally hollow interior and an open end positionable in said alignment member, and at least one aperture extending through the body of said survey tool to communicate fluids from the casing to the hollow interior. The alignment member includes an aperture extending therethrough to communicate fluids from a region above the alignment member to a region below the alignment member, the alignment member otherwise blocking off the communication of fluids through the drill string therepast; and whereby upon placement of the survey tool in the alignment member for the alignment thereof, fluids may pass through the aperture, and thus through the hollow interior of the survey tool and through the alignment member. In another embodiment, the survey tool contains a survey apparatus located therein in a position so as not to interfere with fluid flow therethrough; and the survey apparatus may be operated to obtain borehole or formation information as fluid is flowing therethrough. In another embodiment, a drill shoe having a drill motor and a jetting apparatus is positioned on the end of the drill string, and the survey apparatus steers the drill shoe as the drill shoe penetrates an earth formation. 
     In yet another embodiment, the alignment member includes a stage tool and may further include a float tool to receive a cement shoe thereon. 
     In another aspect, the present invention provides an apparatus for drilling with casing. The apparatus includes casing having a drilling member disposed at a lower portion thereof and a pivoting member coupling the drilling member to the casing, wherein the drilling member may be pivoted away from a centerline of the casing for directional drilling. In one embodiment, apparatus further includes a drilling motor, wherein the pivoting member is coupled to the drilling motor. 
     In another aspect, the present invention provides a survey tool for use while drilling with casing. The survey tool includes a body having a bore therethrough and one or more measurement devices. The survey tool also includes an inlet for fluid communication between the casing and the bore of the body and a bypass valve for diverting fluid in the casing from the inlet. In one embodiment, the bypass valve is in a closed position when the fluid is at a lower fluid flow rate, while a higher flow rate places the bypass valve in an open position. 
     In another aspect, the present invention provides a method of collecting information while drilling with casing. The method includes providing a measurement tool in a casing, the measurement tool having a first inlet and a second inlet. The method also includes flowing fluid through a first channel to actuate the measurement tool and collecting information on a condition in the wellbore. The method also includes increasing fluid flow in the casing and flowing fluid through the second channel to continue drilling. 
     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.