NO20131089L - Apparatus and methods for drilling a wellbore using casing - Google Patents

Abstract

Device and methods for drilling with casing. In one embodiment, a device for dissipating a feeding tube using a diversion device is disclosed. In another embodiment, the device consists of a motor drive system that has been placed in a motor system rack, an axis that has been operatively attached to motor drive systems and where the axis has a passageway, and a lead assembly that has been positioned in such a way that it conducts fluid flow selectively to motor drive system and crawl into the axis. In another aspect, methods and apparatus for drilling a feeding tube in a particular direction into a formation are disclosed. Methods and apparatus for measuring the borehole path into the formation are also described.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application is a continuation in part of U.S. Pat. patent application no. 10/257,662 submitted on 2 April 2001, which application is incorporated herein by reference in its entirety. U.S. Patent Application No. 10/257,662 is the national application phase associated with PCT/GB01/01506 filed on April 2, 2001.

[0002] This application claims support from the U.S. Provisional Patent Application, serial no. 60/444,088, filed Jan. 31, 2003, and this application is incorporated herein by reference in its entirety. This application requests further support from the U.S. Provisional Patent Application, serial no. 60/452,202, filed Mar. 5, 2003, and this application is incorporated herein in its entirety by reference. This application also claims to be supported by the U.S. Provisional Patent Application, serial no. 60/452,186, filed Mar. 5, 2003, and this application is incorporated herein by reference in its entirety. This application requests further support from the U.S. Provisional Patent Application, serial no. 60/452,317, filed Mar. 5, 2003, and this application has been incorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

Field of the invention

[0003] Preparations of this invention refer in general to methods and devices for drilling and completing a well. In particular, the preparations associated with this invention refer to two methods and devices for being able to drill with a casing in a particular direction. Furthermore, the presentations associated with this invention usually refer to areas associated with well drilling, and in particular to well drilling areas associated with drilling to obtain the extraction of hydrocarbons from formations below the surface, where the drilling direction of the wellbore is controlled, and where there is a need to be able to determine the orientation of the drill bit down in the earth . US 5,845,722 discloses a method for sinking a borehole in underground formations with at least one special layer formation that includes different formation pressures with respect to an adjacent formation in the descending direction. A drilling tool associated with the bottom end of a drill string with a drill bit driven by a deep-hole drill bit motor drills out a first portion of a borehole extending to a point near the boundary region of the particular formation. From W02004001180 it appears a guiding device for an offshore drilling installation which comprises at least one drilling riser that extends from a floating support to the guiding device at the seabed.

Description of associated methods.

[0004] In conventional well operations, a wellbore wellbore is formed by drilling to access hydrocarbon-bearing formations. Drilling is accomplished by means of a drill bit mounted on the end of a drill string, commonly known as a drill string. The drill string is often rotated by a top-drive rotation system or a drive pulley on a surface platform or rig. Alternatively, the drill bit can be rotated by a downhole motor mounted on a lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed (that is, pulled out) and part of the casing is lowered into the wellbore. An annulus is formed between the casing string and the formation, and a cementing operation can then be performed to fill the annulus with cement. The combination of cement and casing reinforces the wellbore and facilitates the isolation of some special areas of the formation behind the casing for the production of hydrocarbons.

[0005] It is common to use more than one casing string in a wellbore wellbore. Typically, the well is drilled to an initial designated depth with a drill bit on a drill string. The drill string is then removed, and a first casing string or guide pipe is driven into the wellbore and placed in the drilled part of the wellbore. Cement is circulated into the annulus outside the casing string. The well is then drilled to a designated depth number two, and a casing string or casing number two is driven into the drilled part of the wellbore. The second string is placed at a depth so that the upper part of the second casing string overlaps the lower part of the casing. The second casing string is attached or suspended from the first casing string by means of ties to be able to form a wedge shape against a surface of the first casing. The second string of casing is then cemented. The process can be repeated with additional casing strings until the well has been drilled to a designated depth. In this way, the wells are usually formed with two or more casing strings of ever decreasing diameter.

[0006] As an alternative to the conventional method, a method consisting of drilling with a casing is often used to place casing strings of decreasing diameter within a wellbore wellbore. Casing drilling uses a cutting device (such as a drill bit or a drill shoe) attached to the lower end of the same casing string that will line the wellbore. The entire casing string can be rotated using surface mechanical devices, which ultimately rotate the drill bit so that the drill bit is drilled into the formation. Once the well has been drilled to the designated depth with the casing in place, the casing can be cemented to complete the well. Additional casing strings can be run through the first casing string and drilled further into the formation to form a wellbore wellbore at depth number two, and this process can be completed with subsequent additional casing strings. Drilling with casing is often the preferred method for completing wells, as it is only necessary to run the work string into the wellbore to form and line the wellbore.

[0007] Drilling with casing is practical when it comes to drilling and lining a subsea wellbore well, especially with the completion of well operations in deep water. When a subsea wellbore wellbore is formed, the entire length of the wellbore that has been drilled with a drill string is subject to potential collapse due to the soft formations found on the seabed. In addition, parts of the wellbore that cross regions of high pressure can cause damage to the drilled wellbore during the time between the formation of the wellbore and the casing of the wellbore. Drilling with casing removes these types of time delays and simplifies these problems.

[0008] An alternative method of drilling with casing, which is sometimes used instead of rotating the casing string to drill into the formation, consists of "jet drilling" or pushing the casing into the formation. As hydraulic energy from nozzles in a drill bit is often sufficient to remove the formation without using cutting tools, it is often necessary to jet drill the pipe into the ground by forcing pressurized fluid through the inner diameter of the casing string at the same time as the casing string is lowered into the wellbore . Consequently, the fluid and mud are forced to flow upward outside the casing string, so that the casing string remains largely hollow and can accept casing strings of decreasing diameter that help to line the wellbore. To be able to jet drill the pipe, holes or nozzles can be formed through the lower end of the drill bit and 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 will be largely symmetrical in terms of the drill bit, so that an even amount of fluid is released along the diameter of the casing string.

[0009] In yet another alternative method of drilling with a casing, a motor and a drill bit may be attached to a drill pipe and placed on an end station portion of the first casing string to enable rotary drilling of the casing string into the formation if desired, in addition to to enable jet drilling by lowering the casing string into the formation to proceed. The drill bit can be rotated while the first casing string is lowered into the formation in order to facilitate drilling of the first casing string to a desired depth. After the desired depth has been reached, the drill bit and drill pipe can continue to drill down to a designated depth to enable placement of the second casing string. When the casing string reaches the designated depth, the drill pipe, motor, and drill bit are pulled out of the wellbore while the casing string remains within the wellbore before the casing string is cemented into the wellbore. The second casing string is run down and placed in the wellbore at the designated depth, the motor system is pulled out, and then the second casing string is cemented. Extra costs and time for completing a wellbore wellbore are natural consequences of the current drilling with a casing operation in that the motor system must be pulled out of the wellbore before cementing operation can take place.

[00010] For various reasons, it may be necessary to deviate from the natural direction (for example, substantially vertical) of the wellbore and drill an inclined drilled hole. Casing drilling can also be used to drill an inclined hole, which is commonly referred to as "directional casing drilling."

[00011] In subsea drilling operations, a drilling platform is supported by the underground formation at the bottom of a body of water. The drilling platform is the surface from which the casing parts and strings, cutting devices, and other supplies are lowered to form an underground wellbore wellbore lined with casing. Each platform represents relatively significant costs. In addition, state regulations will only allow a limited number of platforms on a given surface area in a body of water. Consequently, platforms must be spaced apart at a predetermined distance for drilling underground wellbore wellbores. In addition, each platform can only occupy a specified area on the surface of the body of water. Since only a particular number of platforms of a given dimension are permitted on a given surface area, and taking into account the possibly prohibitive financial costs associated with multiple platforms, the number of wellbore wellbores drilled into the underground formation should be the maximum number of wellbore wellbores that can be drilled into the underground formation from the permitted platforms. In this way, hydrocarbon production is made as large as possible, in that increased production of wells increases the hydrocarbons that are available on the surface of the wellbore. Each wellbore wellbore formed is therefore valuable as an independent production well that is directly responsible for production from the hydrocarbon source.

[00012] A common problem with drilling subsea wells arises from an attempt to maximize hydrocarbon production by maximizing the number of wells drilled from slots in a platform with a limited surface area. To be able to drill as many wells as possible, the slots in the platform must be very close to each other. The closer one slot is to another, the more wells can be drilled on a given surface area. Unfortunately, drilling wellbores through closely spaced slots leaves limited room for even small directional deviations when the wellbore is not drilled directly down into the subsea formation. Sometimes the wellbores are randomly diverted and drilled into each other, which causes the wellbores to cross each other. When two or more wells are crossed, at least one well is eliminated as an independent hydrocarbon production source. Consequently, the allowable drilling area from the platform is reduced, which causes a reduction in the production of hydrocarbons from the subsea formation.

[00013] To avoid the crossing of wells, the wells are often drilled at an angle from the slots on the platform. The well holes that are drilled from the outermost slots on the platform are usually drilled at an angle outwards from the platform, and the outgoing angle progressively decreases for the incoming slots. Consequently, the boreholes should deviate slightly from other boreholes to avoid interference with each other. There are also other cases where it may be desirable to drill a hole in a directional manner, such as when drilling at an angle is necessary to reach a production zone.

[00014] Various methods associated with inclined drilling or pushing are currently used. One method consists of pre-drilling a directional hole with a drill bit on a drill string. With this method, a wellbore is drilled into the formation at an angle. The drill string is then removed and a casing string is placed into the pre-drilled hole. With this method, one cannot avoid the wellbore collapsing between the time the hole is drilled and when the casing is inserted into the wellbore. In addition, the increase in time and costs which is a natural consequence of the drill string and the casing string being driven into the wellbore separately, will be disadvantages associated with this method.

[00015] Another method of achieving the deviation consists in first drilling a pilot hole which is smaller in diameter than the desired wellbore and which is at an angle with the desired direction. The hole is then enlarged so that it then becomes possible to run the casing through it. This method involves at least two introductions of the drill string to be able to drill two holes of different diameters, which results in increased time consumption, costs and the possibility that the wellbore may collapse.

[00016] There is therefore a need for a device and methods that are effective in drilling casing into the formation for completion of subsea well operations. There is also a need for pushing methods and devices that can effectively avoid the underground wellbore while drilling the casing string into the formation is in progress to avoid crossing the wellbore.

[00017] Additionally, with the current drilling systems, the drilling tools and casing strings must be driven and/or pulled out many times into and/or out of the wellbore to complete the drilling, casing, casing expansion, and cementing operations, which will result in significant costs and time consumption to be able to complete a well. Therefore, there is a need for a device and a method to perform drilling, casing expansion and cementing operations which can significantly reduce the time and costs associated with the completion of a well. In particular, there is a need for a device and method for performing a drilling operation while lining the wellbore is taking place, which enables a cementing operation to be performed thereafter without the need to recover the motor system used for the drilling operation. In addition, it would be desirable for the device to be able to perform these operations in a number of different locations using different equipment and tools. It would be desirable if the device could perform inclined drilling or pushing operations that produce inclined drilled wells.

[00018] As an alternative casing drilling technique that can be used instead of simply attaching a cutting device to the casing, a

buttonhole assembly ("BHA") with a drill bit is lowered into the formation with a casing. The bit is shown through the lower end of the casing and the BHA is secured to a lower part of the inner diameter of the casing. After the casing has been lowered into the formation, the drill bit is rotated either in a rotary mode by rotating the casing (for example, using the casing as a

drill string) or in a sliding mode by rotating the bit independently of the casing with a wellbore drilling motor. In all cases, as the wellbore is withdrawn, additional lengths of casing are added to the wellbore from the surface as the casing string moves forward with the wellbore.

[00019] Figure 32 illustrates a conventional system for directional

drilling with casing using a BHA 3100. As illustrated, the BHA 3100 with a pilot bit 3108 is typically driven through casing 3104 (lining a wellbore 3102) and secured to a lower portion of casing 3104 with a casing lock 3106. As previously described, the BHA 3100 can be operated in a rotary mode, by rotating the casing from the surface of the wellbore. Alternatively, 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 mounting assembly (or stand) 3114 to bias the conductor in the desired slant direction (hence the motor 3112 is commonly referred to as a "bend housing motor"). The inclined bore hole is drilled by adjusting the bent assembly group 3114 to be able to guide the pilot crown 3108 in the desired inclined direction. The path of the slanted hole is usually dictated by the curvature passing through the centers of the pilot crown 3108, the bend in the motor 3112, and the casing detent 3106.

[00020] The slant drilled hole must be larger than the outside diameter of the casing 3104 to allow the casing to move forward as the wellbore expands. This is typically accomplished by using an expansion drill 3110 to enlarge a pilot hole drilled with the pilot bit 3108. In other words, as the motor 3112 is driven, the pilot bit 3108 is rotated to form the pilot hole, which is then enlarged by the expansion bit 3110 which follows. In order to drive the BHA 3100 through the casing 3104, extendable blades on the extension drill 3110 can be placed in a retracted position. The blades can be extended before drilling of the slanted hole takes place, and again retracted to recover the BHA 3100, through the casing 3104, after the drilling. The BHA 3100 may also include sensing equipment 3109, commonly referred to as logging-while-drilling (LWD) or measuring-while-drilling (MWD), to be able to take path measurements (such as slope and azimuth) and possibly formation measures (for example resistivity, porosity, gamma, density, etc.) at various points along the wellbore which can later be used to calculate the wellbore's trajectory approximately. The MWD equipment usually contains measurement sensors for the wellbore, while the LWD equipment contains formation logging sensors.

[00021] The typical BHA 3100, when connected to casing 3104 with casing stopper 3106, extends approx. 90 to 100 feet (27.4m to 30.5m) below the lower end of casing 3104. The expansion of the BHA 3100 below casing 3104 enables the pilot bit 3108 to form a rat hole (expanded wellbore) below the lower end of casing 3104 .The rat hole has a diameter greater than the outside diameter of the casing 3104 due to the expansion bit 3110.1 the typical directional drilling process using the BHA 3100, the pilot bit 3108 is rotated to drill the casing 3104 into a formation in a directional manner. The casing 3104 is then released from coupling with the casing lock 3106 on the BHA 3100, and the casing 3104 is lowered over the BHA 3100 down to the bottom of the rat hole. The BHA 3100 is finally removed from the wellbore, and the casing 3104 remains in the wellbore.

[00022] The rat hole formation step, and the step consisting of lowering the casing 3104 over the BHA 3100, are necessary when the system in question is used which consists of drilling with casing 3104 using the BHA 3100 in that the bend housing 3114 must have a bend that extends down past the casing 3104 as sufficient to feed the desired path into the inclined drilled hole. Consequently, the directional force drilling applied by the motor 3112 is bent on the flex housing 3114 of the BHA 3100 as the flex housing motor 3112 pushes directly on and against the side of the wellbore. As the flex housing motor 3112 pushes against the side of the wellbore, a resultant force occurs on the opposite side of the expansion bit 3110 and the pilot bit 3108.

[00023] Although the system illustrated in Figure 32 may enable the drilling of an inclined bore hole without removing the casing, the system suffers from a number of disadvantages. As an example, a disadvantage will occur due to a lack of the right type of support between the casing stopper 3106 and the contact point of the pilot crown 3108. Since the typical length between the casing stopper 3106 and the pilot crown 3108 is in the range of 40 feet (10.2m) to 120 feet (36.6m), the BHA 3100 may yield and lean toward a lower end of the slanted hole as downward force (eg, "weight-on-bit") is applied from the surface. This inclination is difficult to control and can have a serious effect on the intended curvature and the trajectory of the inclined drilled hole. Furthermore, without proper supports, excessive lateral and axial vibrations in the BHA 3100 can reduce the removal rate, reduce operating time and/or cause damage to the various components of the BHA 3110, especially when drilling in rotary mode is in progress.

[00024] Yet another disadvantage of the system in Figure 32 consists of the large length of the rat hole that is drilled below the lower end of the casing 3104, where the casing 3104 must be lowered over the BHA 3100. Lowering the casing 3104 over the BHA 3100 in the 90- The 100-foot (27.4m to 30.5m) rathole adds an extra step to the directional drilling with the casing operation. In addition, the system places unnecessary directional force directly on the BHA 3100. Another disadvantage of conventional drilling with the casing systems is that the MWD 3109 does not provide real-time survey information, therefore the trajectory of the inclined hole can only be confirmed after the drilling has taken place. This is regrettable as real-time feedback associated with the wellbore path while it is being expanded can be used to control the drilling process or, for example, adjust the rotation speed of the bit, weight-on-bit, control a rotatable assembly or well motor, etc.), to be able to control the wellbore path. When directional drilling with a drill string is in progress while the well is being drilled, the drilling direction must be controlled or monitored to ensure that the drilling direction does not deviate from the intended direction. This type of monitoring is usually obtained by placing an inspection tool on a well area in a rotationally fixed or known position, and by monitoring signals therefrom to determine the orientation of the drill string underground. Where the drill string is pulled away from the well after the well is drilled, and where the well is then lined, this can easily be achieved by attaching the inspection tool in an assembly group on the drill string, and consequently the inspection tool will stay in the well while the drill bit is at the bottom of the hole. However, when the drill string is later used as a casing, this is not practical and the orientation tool is expensive, and it is therefore undesirable to leave it in the well. In addition, the inspection tool, if left in the well, will create an obstacle to the recovery of well fluid, or to the passage of an additional drilling element further past, and from there through the end of the casing to be able to continue drilling the wellbore even more, and consequently comes to having to be drilled or milled out of the wellbore. Therefore, there is a need in the industry for a mechanism that can provide well orientation tools for situations where the drill string is then used on site (in situ), as a casing for a well, without creating unnecessary obstacles to well fluid recovery, and without the economic consequences of that the inspection tool is left in the hole after the well is finished.

SUMMARY OF THE INVENTION

[00025] Embodiments of the invention provide systems and methods for carrying out drilling, casing and cementing operations which significantly reduce the time and costs associated with the execution of a well. In particular, embodiments of the invention will provide systems and methods for carrying out a drilling operation while lining the wellbore is in progress, which makes it possible to carry out a cement operation afterwards without first having to pull out the motor system that was used during the drilling operation.

[00026] The present invention thus relates to a method for preferably guiding a path of a casing pipe to form a wellbore. The method comprises providing a second casing which is concentrically placed inside a first casing and which is releasably connected thereto. The second casing has a motor system releasably attached therein and which includes an earth removal link. Furthermore, the method includes

[00027] simultaneously lowering the first casing and the second casing into the wellbore, drilling the first casing to a first desired depth with the second casing connected inside the first casing,

[00028] releasing a releasable attachment between the first casing and the second casing, selectively changing a path of the second casing while rotating the soil removal link operatively connected to a lower end of the motor system, while the second casing continues into the formation, and leaving the first casing and the second casing in the wellbore,

[00029] supply a physically alterable binder, preferably cement, from the surface through the motor system and through one or more nozzles in the soil removal joint, and to fill or partially fill gaps between the second casing and the formation.

[00030] In one aspect, embodiments associated with this invention will provide a method of conducting a path with a lined wellbore consisting of providing a drilling assembly consisting of a guide pipe for a wellbore casing and a soil removal joint, and in a directional manner tilt the drill assembly while the soil removal joint is operated and lower the well casings into the earth, leaving the well casing guide tubes down in a well hole that has been created through tilting, operating and sinking.

[00031] The productions of the invention are able to perform these operations in a whole series of places with the help of different equipment and tools and to perform slant-drilled drilling or pushing operations that will produce slant-drilled wells. The preparations of the invention can be used, for example, with an intermediate string, a bent fitting tube, an orientation tool, or without this type of tool. Furthermore, this device can be used to perform an expansion operation on the casing simultaneously with the recovery of the motor system used for the drilling operation.

[00032] In one embodiment, a device for drilling has been provided. The device consists of a motor drive system placed in a motor system rack, an axis that is operatively attached to the motor drive system, where the axis has a passage, and a diversion assembly that has been placed to be able to direct fluid flow of choice to the motor drive system and the passage in the axis. The diverter assembly facilitates switching of fluid flow to the motor drive system during a drilling operation and fluid flow through the passage in the motor system during the cementing operation so that the motor system does not need to be removed in order to perform a cementing operation for the well.

[00033] Another embodiment has a device for drilling with casing, which consists of a casing, a motor system that has been retrievably placed in the casing, and a drilling surface that is operably attached to the axis of the motor system. The motor system consists of a motor drive system which is placed in a motor system stand where the axis is operatively attached to the motor drive system, and where the axis has a passage, and a diversion assembly placed to be able to control direct fluid flow of choice to the motor drive system and the passage in the axis.

[00034] In a further embodiment, a method for drilling and completing a well has been provided. The method consists of pumping drilling fluid or drilling mud onto a motor system that is placed in a casing that rotates an earth removal joint, preferably a drilling surface, attached to the motor system and diverts fluid flow to a passage through the motor system and pumps cement through the passage to the drilling surface. The motor system can be withdrawn after the cement operation, and a casing expansion operation can be performed at the same time as the motor system is withdrawn.

[00035] An additional aspect of this invention involves a method of initiating and continuing the formation of a wellbore by selectively altering the path of the casing string that has been introduced into the formation as it moves down into the formation. In one embodiment, the diversion device consists of the casing string and the cutting device, together with a bend which is directed into the casing string which will influence the casing string to follow the general direction of the bend as a wellbore is formed.

[00036] In a further embodiment, the diversion device consists of a casing string and a cutting device, in addition to a diverter in the form of a sloping wedge shape which is attached in a release manner to a lower end of the casing string. In a further embodiment, the diversion device consists of the casing string, the cutting device, and a fluid deflector. In a further embodiment, the diversion device consists of the casing string, the cutting device, the fluid deflector, and pads that have been placed on the outside diameter of the casing string.

[00037] Another embodiment of the diversion device also involves liquid diversion. In a further embodiment, the diversion device consists of the casing string, the cutting device, and a second cutting device which has been placed on the outside diameter of a portion of the casing string above the cutting device.

[00038] Another aspect of this invention is a device and method for use with fabrications associated with diversion devices. The diverting device is attached in a triggering manner to a drilling device. During operation, after the wellbore path has been diverted by the diversion device, the releasable connection between the drilling device and the diversion device is triggered. The drilling rig is then pulled up to drill through the inner diameter of the casing string to clear any obstructions present within the casing string that was previously used to divert the wellbore. Additional casing strings can then be hung from the casing string, and further operations can then be carried out through the casing string. Yet another aspect of this invention consists of a method and apparatus for inspecting the wellbore path while the casing string is penetrating the formation to form the wellbore.

[00039] Yet another embodiment constitutes a drilling assembly for expanding a wellbore, where the drilling assembly is adjusted to be driven through the casing that lines the wellbore. The drill assembly usually includes a casing lock to be able to secure the drill assembly to the casing, a crown that is attached to a lower part of the drill assembly, an inclined joint to be able to provide the crown with a desired deviation from a center line of the wellbore, and at least one adjustable stabilizer for to support the drill assembly between the casing stop and the bit.

[00040] Another embodiment provides a drilling assembly for extracting a wellbore, to which the drilling assembly is attached to be able to line the wellbore with a casing pipe. The drill assembly typically includes a bit positioned on a lower upper portion of the drill assembly, the bit being adjusted to expand from a first position on the casing to a second position to drill a hole below the casing, the hole having a larger diameter than the the outside diameter of the casing, and at least one stabilizer located between the crown and the lower portion of the casing, the stabilizer having been adjusted from a first position to travel through a casing guiding the wellbore to a second position to connect to an inner surface of the well hole.

[00041] Another embodiment provides a method of drilling with a casing. The method typically includes lowering a drill assembly into a wellbore through a casing, the drill assembly consisting of an adjustable stabilizer and one or more drilling elements, and adjusting one or more support links on the stabilizer to increase a diameter of the stabilizer, and driving the drill assembly to expanding a portion of the wellbore below the casing, where the expanded portion has a diameter greater than the outside diameter of the casing.

[00042] This invention generally provides methods and devices for placing a well tool, such as an inspection tool, in a well location in a fixed position in relation to the drill string, both in terms of distance between the inspection tool and the drill bit, and when it concerns rotational adaptation or orientation of the tool to the drill string and drill bit structure, and the recovery capacity of this type of tool before the well is used for production. In one embodiment, the drill string has been provided with a rotatable float assembly assembly, which includes an internal orientation link where an inspection tool, such as an orientation tool, is received in a known orientation when the inspection tool is placed in a well location within this type of drill string, and which can also be used as a cement float shoe for traditional cementing operations when the casing is to be cemented in place in the wellbore. The inspection tool can therefore be oriented in this way in the drill string to enable important orientation inspections of the drill bit and drill orientation, either based on a sample or continuous use. In another aspect, the inspection tool may communicate information related to the orientation to the surface using mud pulse telemetry, or other methods known to a person of ordinary skill in the art.

[00043] In a further embodiment, the float assembly group includes a profile of a guide shoe with a beveled edge that receives a corresponding profile of a guide shoe with a beveled edge of the inspection tool. The profile of the guide shoe with beveled edge is placed in a stand, in which the inspection tool can be placed, so that the profile of the guide shoe of the inspection tool comes to be flush with the guide shoe of the float assembly group, and in this way the inspection tool is oriented into the drill string. In a further embodiment, the guide shoe profile on the float assembly assembly may include a secondary fitting joint, which will enable the inspection tools to land there which do not include this type of bevel profile guide shoe.

BRIEF DESCRIPTION OF THE PRIORITY MANUFACTURE

[00044] In order that the above-mentioned features associated with this invention can be understood in detail, a more detailed description of the invention as summarized above can be obtained by referring to preparations, some of which are illustrated in the attached drawings. However, it should be noted that the attached drawings only illustrate typical preparations associated with this invention and must therefore not be considered to limit the scope of the invention, as it will possibly consist of other equally effective preparations.

[00045] Figure 1 is a schematic layout of a production associated with a drilling and completion system of a well in an underwater formation.

[00046] Figures 2A and 2B show a cross-section of a preparation associated with a drilling system for a hollow axis motor which is placed in a casing.

[00047] Figure 3 is a cross section of a fabrication associated with a drilling system for a hollow shaft motor illustrating a fluid diversion operation.

[00048] Figure 4 is a partial cross-section of a preparation associated with the diversion system in Figure 3.

[00049] Figure 5 is a cross-section of an embodiment of a drilling system for a hollow shaft motor illustrating a cementing operation.

[00050] Figure 6 is a cross-section of a preparation associated with a drilling system for a hollow axis motor illustrating a system's extraction.

[00051] Figure 7 illustrates a preparation associated with a drilling system that can be used for a drilling and casing operation where the casing can be added during the operation.

[00052] Figure 8 is a cross-section of a manufacture associated with a drilling system for a hollow shaft motor illustrating a drilling operation using a bent fitting pipe.

[00053] Figure 9 is a cross-section of a fabrication associated with a drilling system for a hollow shaft motor illustrating a drilling operation using a bent adapter pipe and the intermediate string.

[00054] Figure 10 is a cross-section of a manufacture associated with a drilling system for a hollow shaft motor illustrating an inspection operation.

[00055] Figure 11 is a cross-section of a preparation associated with a drilling system for a hollow shaft motor which is placed in an expandable casing.

[00056] Figure 12 is a cross-section of a fabrication associated with a drilling system with a hollow axis motor placed in an expandable casing that illustrates an operation for expanding the casing after cementing.

[00057] Figure 13 is a cross-section of the manufacture of a diversion device associated with this invention which is placed within an underground wellbore. The arrester is located below a casing where an earth removal link has been attached.

[00058] Figure 14 is a cross-section of an alternative embodiment for a diversion device associated with this invention that is placed within an underground wellbore. A fluid deflector has been placed within the fluid removal joint attached to the casing.

[00059] Figure 15 is a cross-section of an alternative embodiment for the diversion device in Figure 14 which is placed within an underground wellbore. Stabilizer pads have been placed on the outside diameter of the casing.

[00060] Figure 16 is a cross section of yet another alternative embodiment for a diversion device associated with this invention which is placed within an underground wellbore. A cutting device in the form of an elongate coupling extends outward from the outer diameter of the casing. The right side of the casing axis in Figure 16 has been cut away to show a connection that can be threaded.

[00061] Figure 17 shows an alternative representation of the diversion device associated with this invention which has an eccentric stabilizer placed therein.

[00062] Figure 18 is a cross section of a drilling device for use with the diversion device associated with this invention in the feed configuration. The drilling device is shown after drilling a well into the formation.

[00063] Figure 19 is a cross-section of the drilling device in Figure 18 with drilling through the diversion device after removal from the wellbore.

[00064] Figure 20 is a cross-section of the drilling device in Figure 18 after removal of the drilling device after drilling through the diversion device.

[00065] Figures 21 and 22 illustrate a drilling process that takes place through a casing.

[00066] Figures 23A and 23B are perspective views of the first and second ends of an embodiment associated with a rotatable nozzle.

[00067] Figures 24A and 24B are perspective views of the first and second ends of an alternative embodiment associated with a rotatable nozzle.

[00068] Figure 25 is a cross section of a first embodiment for a nozzle assembly placed in a tool body.

[00069] Figure 26 is a cross section of a second embodiment of a die assembly placed in a tool body.

[00070] Figure 27 is a cross-section of a third embodiment for a nozzle assembly placed in a tool body.

[00071] Figure 28 is a cross-section of a fourth embodiment associated with a nozzle assembly placed in a tool body.

[00072] Figure 29 is a cross-section of a tool body having an internal nozzle assembly for drilling with a casing.

[00073] Figure 30 is a cross-section of a lower end of a soil removal joint having fluid passages passing through it.

[00074] Figure 31 is a cross-section of a casing string that can be used in this invention.

[00075] Figure 32 illustrates an example of a system for directional drilling according to previous methods.

[00076] Figures 33A-D illustrate a system for directional drilling according to an embodiment associated with this invention.

[00077] Figure 34 is a flowchart illustrating examples of operations for directional drilling with a casing according to an embodiment associated with this invention.

[00078] Figure 35 shows a cross-section of an alternative embodiment of a system for directional drilling with casing according to this invention. An eccentric bias pad for the casing is shown on the casing.

[00079] Figure 36 shows a cross-section of a further alternative embodiment of a system for directional drilling with a casing.

[00080] Figure 37 is a cross-section of another embodiment of a directional drill assembly, equipped with an articulating stand.

[00081] Figures 38A-B show an example of an articulating stand according to aspects associated with this invention.

[00082] Figure 39 shows another representation of a directional drilling assembly.

[00083] Figure 40 shows the directional drilling assembly in Figure 45 after the BHA has reached the bottom of the wellbore.

[00084] Figure 41 shows the directional drilling assembly of Figure 45 in operation.

[00085] Figure 42 is a schematic view, in parts, of a directional well hole to be drilled.

[00086] Figure 43 is a cross section of a float assembly group in a well area as shown in Figure 42 and a cross section of an inspection tool that can be received there.

[00087] Figure 43A shows a side view of the inspection tool of Figure 43.

[00088] Figure 44 is a cross-section of the float assembly group in Figure 43, showing an inspection tool in section, received and inserted therein.

[00089] Figure 45 is a cross section of a float assembly as in Figure 44, showing an alternative embodiment of an inspection tool shown partially in section to be received therein.

[00090] Figure 46 is a partial cross-section of the float assembly assembly of Figure 45, showing the inspection tool in and landing on the float assembly assembly.

[00091] Figure 47 shows a partial cross-section of a float assembly having a wellbore inspection tool or sensor located therein.

[00092] Figure 48 shows a representation of an inspection tool assembly according to aspects associated with this invention.

[00093] Figure 49 shows the inspection tool assembly in Figure 48 in the inspection mode.

[00094] Figure 50 shows the inspection tool assembly in Figure 48 in drilling mode..

[00095] Figure 51 shows the bypass valve associated with the inspection tool assembly in Figure 48 in the closed position.

[00096] Figure 52 shows the bypass valve associated with the inspection tool assembly in Figure 48 in the open position.

[00097] Figure 53A is a cross-sectional elevation of a drill bit nozzle for the earth.

[00098] Figure 53B is a cross section through section y-y in Figure 53A.

[00099] Figure 54 shows an alternative production of a crown nozzle which has been largely produced from non-metallic metal.

[000100] Figure 55 shows a cross-section of an alternative embodiment for a diversion device that is placed within an underground wellbore for use in directional drilling.

[000101] Figure 56A is a cross-section of a diversion device used for expanding a casing.

[000102] Figure 56B is a cross-section of the diversion device in Figure 56A in the process of expanding the casing.

[000103] Figure 57 is an upward cross-section of an earth removal joint for use in this invention.

DETAILED DESCRIPTION OF THE PRIORITY PRODUCTION

[000104] In the following embodiments associated with this invention, the casing may be alternately jet drilled and rotated to form a wellbore. Casing string rotation can be achieved either by rotating the entire casing or by rotating the cutting device relative to the casing using a mud motor that has been operatively attached to the casing.

[000105] Preparations associated with this invention provide systems and methods for carrying out drilling with casing operations which will reduce time and costs for the completion of the well in a significant way. In particular, some inventions associated with this invention will provide systems and methods for carrying out a drilling operation while the wellbore is being lined, which makes it possible to carry out a cementing operation afterwards without first having to extract the motor system used for the drilling operation.

[000106] Figure 1 is a schematic view of a preparation associated with a system 100 for drilling and completing a well in a formation 112 underwater 108. Although the system 100 is shown in connection with a deep-sea drilling operation, preparations associated with the invention can be used in drilling operations both on land and underwater 108. As shown in Figure 1, the system 100 includes a first, outer casing 185, a second, inner casing 195, and a drilling system 157. The inner casing 195 fixed in a manner that can be released, and preferably releasably latched onto the outer casing 185, and the drilling system 157 is releasably secured, and preferably releasably latched, into the inner casing 195. The drilling system 157 includes an earth removal link, preferably in the form of a drill bit or a drill shoe 167 that protrudes on the outside of a terminal part 147 of the outer casing 185. An intermediate string or the drill string 165 attaches the drilling system 157 to a ship or a platform 155 on the water surface 108. The system 100 can be used to drill and line a well in the formation 112 below the seabed or mud line 160.

[000107] Typically, the casing 185 or 195 consists of casing parts. Each part of the casing has an external and an internal end piece which is threaded to be able to be attached to another part of the casing above and/or below the casing part. A casing string includes more than one section of casing that is attached to each other in a threaded manner. As used herein, casing may include a section of casing or a string of casing.

[000108] Figures 2A and 2B show a cross-section of an embodiment associated with a drilling system for a hollow axis motor 200 placed in a casing 219. The drilling system for the hollow axis motor 200 illustrates an embodiment associated with the drilling system 157, and the casing 219 represents the second casing 195. The drilling system for the hollow shaft motor 200 generally consists of a casing stopper 211, a hollow shaft motor 221, and a drill shoe 270. The drilling system for the hollow shaft motor 200 may include a guide assembly 203 attached to a casing stopper 211.1 an embodiment, the guide assembly 203 includes a cone-shaped part 204 and a tubular part 206. The cone-shaped part 204 guides mechanical devices introduced from the surface or drilling fluid or drilling mud into the tubular part 206. This type of mechanical devices can include the intermediate string or a drill string 207, a closing ball, a locking dart 286 (see Figures 5 and 6 ), and other devices attached to a lead wire. The tubular part 206 also provides a whole series of collection seats, such as a spear seat 08 for receiving a stinger attached to the intermediate string 207 and an orientation tool landing seat 209 for receiving an orientation tool in order to perform an inspection. The tubular part 206 is attached to the casing stopper 211 and provides a fluid passage which is connected to a liquid passage in the casing stopper 211.

[000109] The casing detent 211 is secured to the hollow shaft motor 221 and provides a mechanism for securing the drilling system for the hollow shaft motor 200 against an inner surface of the casing 219.1 one embodiment, the casing detent 211 includes a set of gripping links, preferably ties, which can is retracted 212, located between an upper mass 214 and a lower mass 216. The lower mass 216 includes one or more angled surfaces 218 that push the ties 212 outward when the ties 212 are pushed against the angled surfaces 218. A locking mechanism, preferably a locking ring 213, is used to hold the ties 212 in the set position against the inner surface of the casing 219 after the ties 212 have been withdrawn. The locking ring 213 can be spring-loaded with a coil spring 222 and released from a locking position by breaking one or more shear pins 224.

[000110] An upper cup seal assembly 226 is placed on an outer surface of the upper mass 214 to provide a seal between the casing stopper 211 and the casing 219. The casing stopper 211 includes an axial tube 228 which provides a fluid passage through the casing stopper 211 to the the hollow shaft motor 221. One or more bypass slots 217 may be placed on the axial tube 228 and on the upper mass 214 to facilitate fluid flow (eg, drilling fluid or drilling mud) during extraction of the hollow shaft motor drilling system 200. The lower mass 216 on the casing stopper 211 is attached to the hollow shaft motor 221.

[000111] The hollow shaft motor 221 provides the mechanism for rotating the drill joint 270 (eg, a rotary drill plate on a drill shoe). In one embodiment, the hollow shaft motor 221 includes a stand 242, a motor drive system 244, the shaft 246, and a fluid diversion assembly 248. The stand 242 includes an upper slot 249 that provides the connection to the casing stopper 211 and continues the axial passage 228 from the casing stopper 211. A lower cup seal 251 may be placed on an outer surface of the rack 242 to provide a seal against the inner surface of the casing 219.

[000112] In one embodiment, the motor drive system 244 is a hydraulic motor system powered by fluids (eg, drilling fluid or drilling mud) pumped through the motor drive system 244. The motor drive system 244 can be a stator system or a turbine system and rotates the shaft 246. The shaft 246 is placed axially along the hollow shaft motor 221 and includes an axial passage 223 attached to the axial passage 228 from the casing stopper 211. Fluid diversion assembly 248 is located on an upper portion of the axial passage 223 to be able to divert fluids into the motor drive system 244 or direct fluid flow through the review 223.

[000113] In one embodiment, the fluid diversion system 248 includes a closure sleeve 252, one or more diversion slots 254, and a shear ring 256.1 normal drilling operations, the shear ring 256 holds the closure sleeve 252 in an open position allowing the diversion slots 254 to divert fluid into the motor drive system 244. In order to move the closure sleeve 252 to the closed position (For example, where the diversion slots 254 are blocked from directing fluid into the motor drive system 244), the shear ring 256 is interrupted by mechanical means, for example, by dropping a ball 261 (see Figure 3) from the surface. The fluid diversion system 248 also includes a rupture plate 258 and an extruding ball seat 260 to facilitate movement of the closure sleeve 252 to a closed position that shuts off fluid supply to the motor drive system 244 and diverts fluid flow through the axial passage 223 in the shaft 246.

[000114] The extruding ball seat 260 includes a seat opening and can be made of a brittle material, such as brass, aluminum, rubber, plastic, mild steel, and other material that can be opened, extruded, or expanded when a predetermined pressure is applied to the seat slot. For example, when a ball 261 (see Figure 3) has been dropped into the extrudable ball seat 260 with fluid continuously pumped behind the ball, 261, pressure builds up against the extrudable ball seat 260, and when a predetermined pressure has been reached, breaks the cutting ring 256 and the sleeve

252 moves downward and closes the slot(s) 254. Then, another predetermined pressure is reached and the extrudable ball seat 260 opens and allows the ball 261 to move through the seat slot, with sufficient force to break through the rupture disc 258. The rupture disc 258 may be fabricated of a flanged material which, when ruptured or broken by a bullet 261, usually opens in a four-leaf clover pattern and does not break into pieces. Once a rupture disk 258 has been ruptured, fluid flow is directed through the passage 223 in the axis 246 of the drill shoe 270.

[000115] The drill shoe 270 is placed on an end station portion of the casing 219. The drill shoe 270 includes a mounting part 272 that can be attached to the end of the casing 219. The mounting part 272 secures the drill shoe 270 to the casing 219. The drill shoe 270 includes a rotating drilling surface 274 that is placed on a rotating manner to the mounting part 272. A set of bearings 276 has been placed between the mounting part 272 and the rotating drilling surface 274 to facilitate the rotational movement of the rotating drilling surface 274. As another alternative, a ball joint (not shown) can be used instead of lower 276. Use of a ball joint will facilitate adjustment of the angle of the drilling surface 274 (or the azimuth of the crown surface) in relation to the axes of the casing 219. A spindle 278 is attached to the rotating drilling surface 274. The spindle 278 is attached to an end station part of the axis 246 of the hollow shaft motor 221 which provides the rotational motion of the rotating drilling surface 274. The spindle 278 includes r is a central passage 229 which is connected to the axial passage 223 in the shaft 246 of the hollow shaft motor 221. The central passage 229 facilitates fluid flow (for example, drilling mud or cement) to one or more nozzles 227 (preferably crown nozzles) on the rotating drilling surface 274 The nozzles 227 enable fluid flow out from the drilling surface 274 and into the annulus between the casing 219 and the formation to facilitate drilling and cementing operations. A dart seat 282 has been placed on the central passage 229 to receive a dart which can be used to seal the passage 229.

[000116] Figures 2A and 2B illustrate a preparation associated with the drilling system 200 that can be used for a drilling and casing operation where the casing 219 is of a set length and the drill pipe (or intermediate string) 207 can be added from the surface during the operation. In one embodiment, the hollow shaft motor drilling system 200 may be used offshore for deep sea drilling where 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 placed on an inner casing 195 in a deployed casing configuration, as shown in Figure 1. The inner casing 195 can be locked to an outer casing 185 by means of a J-slot mechanism (not shown). In one embodiment, the outer casing 185 is a 36-inch (0.91 m) diameter casing, while the inner casing 195 is a 22-inch (0.56 m) diameter casing, and a drill shoe 270 or 135 with a The 26-inch (0.66m) drill face or drill bit is attached to the tip of the inner casing 195. The deployed casing configuration is attached to the surface platform 155 by means of the intermediate string 165 and is lowered to the seabed 160.

[000117] To begin the drilling operation, again referring to Figures 2A and 2B, drilling fluid or drilling mud is pumped from the surface through

the intermediate string 207 which is attached to the hollow shaft motor drilling system 200 to provide the hydraulic power to drive the motor drive system 221 which rotates the drill shoe 270. The outer casing 185 (see Figure 1) is jet drilled/drilled to a first designated depth with the inner casing 195, 219 blocked inside. The outer casing 195, 219 may be directionally drilled into the formation using any of the arrangements shown in Figures 13-20 and described below. By pushing on the outer casing 195, 219, the direction of the wellbore can be set in motion so that the subsequent casing can be drilled further into the wellbore at an angle.

[000118] Once this first designated depth has been reached, the inner casing 195, 219 is released from the outer casing 185 (eg, by twisting the inner casing 195, 219 through the J-slot mechanism) and continues to be drilled/ the jet drill until a designated depth number two is reached. The methods and devices in Figures 13-20 described below may also be applied to the outer casing 185. When the inner casing 195, 219 has reached the designated depth, as shown in Figure 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 drive system 244 and divert flow to the passage 223 in the shaft 246. The ball 261 is then pressed from the surface to a first predetermined pressure to the cutting ring. 256, and consequently the sleeve 252 is moved to a closed position. At a predetermined pressure number two, the ball 261 is extruded through the seat 260, then collides with and ruptures the rupture plate 258, as shown in Figure 3.

[000119] Figure 3 is a cross section of a fabrication associated with a drilling system for a hollow shaft motor 200 illustrating a fluid diversion operation. Figure 4 is a partial cross-sectional view of an embodiment associated with a diversion system 248 in a closed position where the ports 254 are closed from supplying fluid flow to the motor drive system 244. In order to open the fluid flow to the passage 223 in the axis 246, fluid (for example, drilling fluid, drilling mud, or cement) is pumped in behind the ball 261 to be able to build up a pressure against the ball seat 260, and when sufficient pressure has been reached, the cutting ring 256 is broken and the sleeve 252 closes the slot(s) 254. When a predetermined pressure number two has been reached, the ball 261 penetrates the extrudable ball seat 260 and breaks through the rupture disk 258, allowing fluid flow through the passage 223. The ball 261 travels through the passage 223 and falls into a hole 284 (as shown in Figure 2) on the spindle 278. When the diversion system 248 has been set for direct fluid flow through passage 223, a cementing operation can be performed.

[000120] Figure 5 is a cross-section of a preparation associated with a drilling system for a hollow axis motor 200 which illustrates a cementing operation. A binder that can be changed to physical, preferably cement, can be pumped from the surface through the hollow shaft motor's drilling system 200 and through one or more crown nozzles 227 in the drilling surface, 274, and fills or partially fills spaces between the casing 219 and the formation. After sufficient cement has been pumped through to cement the casing 219 in place, a stopcock 286 is inserted from the surface to close off the central passage 229 in spindle 278. The stopcock 286 is used to prevent backflow through the central passage 229 of spindle 278 and stopping flow through one or more crown nozzles 227 on bore surface 274. Alternatively, instead of or in addition to the stop dart 286, a float valve can be used to prevent backflow of fluid through the drill shoe 270. The stop dart 86 is displaced down to the dart seat 282 of mud which is pumped in behind the dart 286 from the surface. When the locking dart 286 has been secured onto the dart seat 282, a system extraction can be performed to be able to extract the motor system 221 and the casing locking device 211.

[000121] Figure 6 is a cross-section of a manufacture associated with a drilling system for a hollow axis motor 200 illustrating an extraction system. With the detent dart 286 in the dart seat 282, the ties 212 on the casing detent 211 can be released through a mechanical jerking action (eg, by means of the intermediate string 207 or a lead wire) which cuts off the trigger shear pin 224. When the trigger shear pin 224 is broken, the ties 212 fall together inwardly and released from the inner surface of the casing 219, and the motor system 221 and the casing stopper 211 can be extracted (eg, can be physically lifted) from the surface by pulling back or upward on the intermediate string 207.1 during the extraction operation, the shaft 246 of the motor system 221 is disengaged from the spindle 278 on the drill shoe 270, leaving the stop dart 286 in the dart seat 282. As the casing stop 211 is moved up towards the surface, the bypass slots 217 can be opened to allow the remaining mud in the system to flow through the bypass slots 217 into the casing 219 .If a float valve is used in the drill shoe 270, the motor system 221 can t is extended by mechanical means other than the intermediate string (or drill pipe) 207, such as, for example, a wireline, a pipe coil, a coil pump spindle, etc.

[000122] As described above, the hollow axis motor's drilling system 200 will simplify drilling with the casing and make it possible to cement the well in a single operation without first needing to pull out the motor system 221 and the drill bit 270. A considerable amount of time can be reduced when applies to the drilling and lining of a well, which will result in substantial financial savings. Productions associated with the hollow axis motor's drilling system 200 can be used in a whole range of applications.

[000123] Figure 7 illustrates a preparation associated with the drilling system 200 which can be used for a drilling and casing operation where the casing can be added during the operation. To begin the drilling operation, drilling fluid or 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 drive system 221 which rotates the drill shoe 270. The casing 219 is jet drilled/drilled to a designated depth. The ability to drill a hole without rotating the casing 219 while adding casing at the surface can reduce the time required to perform the drilling operations. As another alternative, the casing 219 may be rotated by surface equipment (eg, a top-drive rotation system, drive disc, etc.) during the jet drilling/drilling operation without or in addition to rotating the drill shoe 270. Once the casing 219 has reached the designated depth, a fluid diversion operation, a cementing operation, and a withdrawal operation may be performed, similar to the above description in connection with Figures 3-6, except that fluids are pumped down from the surface through the inner diameter of the casing 219 instead of the intermediate string 207.

[000124] Preparations associated with the invention can also be used to perform directional drilling. Figure 8 is a cross-sectional view of an embodiment associated with a drilling system for a hollow shaft motor 800 illustrating a drilling operation using a bent adapter pipe 802. As shown in Figure 8, the motor system 221 and drill shoe 270 are latched onto a bent adapter pipe 802. the fitting pipe 802 is threaded onto the casing where the casing 219 is rotated on the surface during straight hole sections and slides during directional sections to drill the casing 219 into the formation at an angle a. Figure 9 is a cross section of a fabrication associated with a drilling system for a hollow shaft motor 800 illustrating a drilling operation using a bent adapter pipe 802 and the intermediate string 207. This illustration facilitates the addition of an intermediate string 207 to a bent adapter pipe assembly 800 from the surface. The casing 219 is of a set length, while the drill pipe (eg, the intermediate string) 207 is added at the surface. Both Figures 8 and 9 show a bent angle a (for example, one degree bend) from the main bore axis. Use of a bent adapter pipe 802 makes it possible to drill a slanted hole or to perform a push operation, without having to rely on a jet drilling/boring operation. Typically, in order to keep the drilled hole straight, the casing 219 is rotated when the casing 219 is not sliding or is in a sliding mode. In an alternative embodiment, the intermediate string 207 may not be attached during the drilling operation, but may be used to extract the motor system 221. When the intermediate string 207 is used, it would be advantageous (eg, faster) to perform the cementing operation using the intermediate string 207 .

[000125] Preparations associated with the invention can be used to perform an inspection operation in order to be able to determine the drilling direction. Figure 10 is a cross-section of a preparation associated with a drilling system for a hollow axis motor 200 which illustrates an inspection operation. At any time during the drilling operation, if an inspection is required to determine or confirm the direction of drilling, an inspection operation can be performed by lowering an orientation device 1010 into the guide 204.1 an inspection operation, the intermediate string 207, if one is used, is withdrawn to enable the use of the orientation device 1010. The orientation device 1010 is introduced into the land seat 209 to determine the azimuth deviation of the drilled well. After the inspection is completed, normal drilling operations can resume and corrections can be made to guide or deviate the well in the desired direction. The inspection operation can also be performed while drilling in a "measure-while-drilling" operation is taking place, so that the angle of the casing can be adjusted continuously so that drilling can take place without disturbing the drilling and casing operation.

[000126] Manufactures associated with the invention can be used in a drilling and casing operation where the casing 1102 can be cemented and expanded at the same time on the casing 1102. Figure 11 is a cross section of a manufacture associated with a hollow axis motor drilling system 1100 which is placed in an expandable casing 1102 The hollow shaft motor drilling system 1100 includes similar components to the drilling system 200 described above except that the rack 1142 of the hollow shaft motor drilling system 1100 is enlarged (as opposed to the rack 242) to conform to an enlarged end station portion 1103 of the expandable casing 1102.1 addition includes the casing stopper 1110, not bypass openings such as the bypass openings 217 on the casing stopper 211. The drilling and cementing operations as described above can be performed in a similar manner using the hollow shaft motor drilling system 1100. After the drilling and cementing operations have been performed, the expandable casing can 1102 is extended or enlarged from the inside by means of the enlarged stand 1142.

[000127] Figure 12 is a cross-section of a fabrication for a hollow shaft motor drilling system 1100 placed 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 stop dart 1186 has been placed on the dart seat 1182, the ties 1112 on the casing stop 1110 are released to enable the extraction of the motor system 1140 which causes the expansion of the casing 1102. The casing 1102 can be expanded by mechanically pulling up the enlarged stand 1142 (eg, using the intermediate string such as 207) or by pumping fluid (eg mud) downward to push the stand 1142 upwards, or by a combination of both of these methods . In one embodiment, as the motor system 1140 is pulled up (eg, by means of the intermediate string), mud is pumped through the passages 1128 and 1150, filling up the area within the casing 1102 between the rack 1142 and the spindle 1178 of the drill shoe 1170. As more mud is pumped down from the surface, pressure builds between rack 1142 and spindle 1178 and pushes rack 1142 upwards. The rack 1142 is pushed against that surface of the casing 1102, expanding the casing 1102 as the rack 1142 moves upward toward the surface. With the withdrawal of the motor system 1140, the casing 1102 is expanded to a larger internal diameter. Furthermore, since cement between casing 1102 and the formation has very recently been pumped there, and has not been cured or dried, the expansion of casing 1102 squeezes the cement into remaining voids in the formation, resulting in a better seal or a stronger cement job on casing 1102 in the formation.

[000128] With the embodiments of Figures 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 engine's internal drilling system, as described in connection with Figures 1-12.1 addition, the additional casing may be cemented into the formation and expanded by the engine's drilling system.

[000129] In an additional aspect associated with this invention, the engine's drilling system 200 or 1100 as described in connection with Figures 1-12 can be used in connection with preferably diverting a casing in the form of a casing part or the casing string in the wellbore in a direction that uses the casing, as shown and described in relation to Figures 13-20.1 and the embodiments described herein, the "casing string" refers to one or more parts of the casing. More than one part of the casing is attached in a threaded manner to each other. Figure 13 shows a diversion device 10 associated with this invention which is placed in a well hole 30. The well hole 30 is a hole that has been drilled in an underground formation 20. The diversion device 10 consists of a cutting device which is 50 attached to a lower end of a casing string 40. The casing string 40 is fed into the formation 20. The cutting device 50 has perforations 55 passing through it which enable fluid circulation between the wellbore 30 and the casing string 40.

[000130] Diverter device 10 also consists of a diverter 60 which is attached to the lower end of the casing string 40 below the cutting device 50. The diverter 60 is attached to the lower end of the casing string 40 by means of a fastening device 65 which can be released. The releasable fastening device 65 is preferably a connection that can be cut. The diverter 60 is preferably an inclined wedge shape which is attached to a part of the casing string 40 by means of the releasable fastening device 65. The diverter 60 has securing profiles 70 which are placed on the lower end which are openings formed within the diverter 60 to be able to grip roofs in the formation 20. The securing profiles 70 provide traction to the diverter 60 while the casing string 40 penetrates the formation 20, preventing a rotating movement of the diverter 60.

[000131] As another choice, the casing string 40 on the diversion device 10 can have a landing seat 45 which is placed internally above the cutting device 50. The landing seat 45 is in a slot where you can place a. inspection tool (not shown). Placing the inspection tool onto the landing seat 45 enables the angle at which the wellbore 30 is drilled in relation to a surface 5 of the wellbore 30 to be determined, and allows the correct type of adjustment to the direction and/or angle of the wellbore 30. To determine at what angle the wellbore 30 is drilled, the inspection tool is first calibrated on surface 5. The inspection tool is then driven through the casing string 40 and into the landing seat 45. Once it has been secured within the landing seat 45, a second reading is taken by the inspection tool, which shows at what angle the wellbore 30 is drilled in relation to the surface 5. The inspection tool and the land seat 45 allow uninterrupted drilling with the casing while the conditions and direction of the wellbore 30 are inspected. Adjustments to the direction of the wellbore 30 can be carried out during the drilling operation. The inspection tool is preferably a gyroscope, which is known to those skilled in the art.

[000132] While the operation is in progress, the diversion device 10 is drilled into the formation 20 using an axial movement to be able 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 simultaneously with the axial movement of the casing 40 so that fluid flows downward through the inner diameter of the casing 40, through one or more nozzles 55, into the wellbore 30, and up through an annular spaced area 90 between the outer diameter of the casing 40 and the inner diameter of the wellbore 30 to the surface 5. When the diversion device 10 has reached a predetermined depth within the wellbore 30, in one embodiment, a downward axial force calculated to release the releasable fastener 65 will be forced onto the casing 40 from the surface 5. The releasable the attachment device 65 triggers in such a way that the casing 40 with the cutting device 50 which is attached until it is moved relative to the diverter 60. Other embodiments not shown may allow an object to be dropped from the surface, such as a ball or a dart, to trigger the diverter device 10 from the casing 40. Other embodiments not shown may also include signals from the surface such as shock pulses that will cause tripping of the diversion device 10 from the casing 40. Still other embodiments not shown may include the use of hydraulic pressure supplied from the surface through the casing 40 or through a separate line such as the intermediate string to causing release of the diverter device 10 from the casing 40. Downward force from the surface 5 is applied to the casing 40, which drives the casing 40 along an upper side 61 of the diverter 60, which remains in the same position within the wellbore 30. The obstruction caused by the diverter 60 forces the lower end of the casing 40 to deviate 10 from the original axis at an angle which stood rt seen corresponds to the drop from the upper side 61 of the deflector 60, which causes the casing 40 to preferentially move in one direction. The inspection tool can be placed within the landing seat 45 to determine at what point the desired deviation angle has been reached. When the desired deviation angle has been achieved, a curing operation is performed, when curing fluid, such as cement, is introduced into the casing 40 from surface 5. The curing fluid flows downward into the casing 40, through one or more nozzles 55, into the wellbore 30 and up into the annulus area 90. The curing fluid then fills up the annulus area 90 to anchor the casing 40 within the wellbore 30. The diverter 60 remains permanently within the wellbore 30.

[000133] Additional casing (not shown) can then be drilled into the formation 20 below the casing 40 using rotational and/or axial force. The casing 40 acts as a template for the angle followed by the additional casing strings, so that the additional casing strings are inclined in the prioritized direction. As the extra casing strings hang from the casing 40, the extra casing strings will deviate in the desired direction at an angle where the casing 40 was inclined. A hardening operation with hardening fluid is performed 25 on additional casing strings as described above in relation to the casing 40.

[000134] Figure 14 shows an alternative embodiment of a diversion device 110 associated with this invention. Diversion device 110 is used to form a wellbore 130 in a formation 120. The diversion device 110 consists of the casing string 140 where a bend is introduced into a part of the casing string 140 to divert the path 30 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 coaxial with the axis of the casing string 140. An arc is therefore integrated into the casing string 140 to drive the casing string 140 to form the wellbore 130 diverting path. Figure 14 illustrates the introduction of the bend into the casing string 140 by connecting component parts from the casing string 140 by external threads 135 which mate with internal threads 125 to form a threaded connection. In the shown embodiment associated with the diversion device 110, the internal and external threads 135 and 125 are oriented towards the casing string 140 so that the connection of the component parts places a lower part 136 of the casing string 140 below the threaded connection at an angle from the vertical axis, so that the lower the part 136 of the casing string 140 is at an angle relative to an upper part 134 of the casing string 140. The internal threads have not been cut coaxially into the lower part 136 of the casing string 140, so that the lower part 136 of the casing string 140 is bent or skewed relative to the upper portion 137 of the casing string 140. As shown in Figure 14, the lower portion 136 of the casing string 140 is at an angle inclined to the right of the upper portion 137 of the casing string 140, which has bitten positioned generally vertically in relation to a surface 105 on the wellbore 130.

[000135] Diverting device 110 further consists of a cutting device 150 which is attached to a lower end of the casing string 140. At a location that is not located in the middle of the vertical axis of the casing string 140, one or more fluid deflectors 175 are formed through the casing string 140 and cutting device 150. The liquid deflector 175 is preferably one or more nozzles through the casing string 140 and the cutting device 150 which are at an angle outwards in relation to the axis of the casing string 140 in the same direction as the liquid deflector 175 is inclined. The liquid deflector 175 is inclined and at an angle in the direction where it is desired that the wellbore 130 be diverted, which is the prioritized direction of the wellbore 130.

[000136] A float assembly assembly is also part of the diverter assembly 110. A float assembly assembly 115.is a pipe forming compound that prevents fluid from flowing back up the inner diameter of the casing string 140 after the curing fluid has been forced downward into the casing string 140 to set up the cementing operation ( described below). In addition, the float assembly group 115 will avoid fluid flowing from the formation 120 into the casing string 140 in order to reduce frictional resistance while the casing string 140 is driven into the formation 120. The float assembly group 115 consists of the ball seat 102 where a ball 101 has been placed originally as shown in figure 14. The ball seat 102 may also be any type of one-way control, including a flapper valve. The diversion device 110 further includes a landing seat 145 for an inspection tool (not shown), which is operated in the same manner as described above in connection with the landing seat 45 in Figure 13. The float assembly group 115 and the landing seat 145 are preferably made of material that can be drilled such as aluminum or plastic , so that it can be drilled through after the casing string 140 has been set within the wellbore 130..

[000137] Figure 15 is an alternative embodiment of the diversion device 110 i

Figure 14. The diversion device 210 in Figure 15, which forms a well hole 230, consists of the same parts as those in Figure 14; and therefore those parts which are alike are indicated by 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.

[000138] The diversion device 210 in Figure 15 also consists of one or more pads 285 that have been placed on the outer diameter of the casing string 240. Ideally, the pads 285 should be located on the outer diameter of the casing string 240 on the opposite side of the fluid deflector 275. After as the casing string 240 is drilled deeper into the formation 220, the diversion device 210 will encounter increasing friction, making it more and more difficult to drill the wellbore 230 into the formation 220. The pads 285, which have been placed vertically at regular intervals along the casing string 240, have tasked with reducing the friction encountered in the formation 220. Furthermore, the pads 285 will assist in positioning the casing string 240 obliquely outward at the increasing angle in the priority direction by keeping the casing string 240 away from direct contact with the inner diameter of the wellbore 230 The cushions 285 maintain the cutting device 250 as it moves outwards and prevent it from falling over. sled vertically adjacent to the axis of the upper part of the casing string 240.

[000139] The operation of the diversion devices 110 and 210 in figures 14 and 15 is similar, so that these will be described in connection with each other. During operation, the diversion device 110, 210 is drilled into the wellbore 130, 230 axially by means of downward force supplied from the surface 105, 205. The cutting devices 150, 250 are drilled 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 downward movement of the diversion device 110, 210 onto the formation 120, 220. The fluid forms a path for the diversion device 110, 210 in the formation and prevents mud and rocks from the formation 120, 220 to fill up the inner diameter of the casing string 140, 240. Fluid flows through the casing string 140, 240, through the float assembly 115, 215, through the fluid deflector 175, 275, and into an annular space space 190, 290 between the outer diameter of the casing string 140, 240 and the inner diameter of the wellbore 130, 230. On the way, the liquid tends to flow into the area that has the least obstruction. The fluid deflector 175, 275 drives the fluid outward into the formation 120, 220 at the same angle as the priority direction associated with the vertical axis of the casing string 140, 240, where there is no obstruction. In this way, fluid flow is diverted by option 5 out of a portion of the casing string 140, 240 to be able to form a diverting path for the wellbore 130, 230. The concentrated fluid flows into only a portion of the formation 120, 220 and 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 can move with less frictional resistance than the alternative paths through the formation 120, 220. The lower portion 136, 236 of the casing string 140 , 240 has accordingly been placed obliquely at an angle from the vertical axis of the upper part 137, 237 casing string 140, 240, in the general direction and in the general angle of the fluid deflector 175, 275, so that the wellbore 130, 230 is in a angle in the prioritized direction and that the trajectory of the wellbore 130, 230 is diverted in a corresponding manner.

[000140] In addition, the fluid tends to flow outward at the angle located on the vertical axis where the bend in the casing string 140, 240, in this case the bend produced by the internal and external threads 125, 225 and 135, 235, has inclined the diverter device 110, 210. Accordingly, the lower portion 136, 236 of the casing string 140, 240 is driven at an angle in the priority direction with respect to the upper portion 137, 237 of the casing string 140, 240 due to the fluid deflector 175, 275 and the threaded connections 125, 225 and 135, 235.1 the representation in Figure 15, the pads 285 further encourage the diversion device 210 in the desired direction by reducing the friction of the casing string 240 against the formation 220 along the way down, in addition to supporting the lower end of the casing string 240 with the cutting device 250, and will consequently prevent the cutting device 250 from falling back into the vertical angle with respect to the axis p to the casing string 140, 240. In this way, regardless of the design involved, the path of the casing string 140, 240 and, consequently, the wellbore 130, 230, is diverted in the desired direction to avoid crossing with other wellbores.

[000141] 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, pressure isolated curing fluid such as cement can optionally be introduced into the wellbore 130, 230 from the surface 105, 205 through the casing string 140, 240. The curing fluid flows through the casing string 140, 240, through

the float assembly 115, 215, through fluid deflector 175, 275, and then beyond the annulus region 190, 290. The float assembly 115, 215 functions in many ways as a control valve, in an open position and allows curing fluid to flow downward through the casing string 140, 240, and into the closed position and prevents curing fluid from flowing back up through the casing string 140, 240 toward the surface 105, 205. Specifically, the curing fluid, as it flows into the casing string 140, 240 from the surface 105, 205, will force the ball 101 , 201 downwards within the float assembly 115, 215 and out of the ball seat 102, 202. Curing liquid can consequently flow around the ball 101, 201 and through the float assembly 115, 215 and then flow into

the annulus region 190, 290. The curing fluid solidifies within the annulus region 190, 290 to secure the casing string 140, 240 within the wellbore 130, 230. When curing fluid is not 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 placed in the ball seat 102, 202 so that the curing liquid cannot flow back upwards within the casing string 140, 240 towards the surface 105, 205.

[000142] After the casing string 140, 240 is cured, the float assembly 115, 215 and the landing seat 145, 245 can be drilled through by a cutting device. Additional casing strings (not shown) can then be suspended from the casing string 140, 240. The additional casing strings are inclined at an angle in connection with the vertical axis in that the casing string 140, 240 guides the additional casing strings in their general direction and angle. The additional casing strings are cured with curing fluid just as the casing string 140, 240 was cured.

[000143] Figures 14 and 15 show a bend introduced into the casing 140, 240 on the threaded connection consisting of internal and external threads 125, 225 and 135, 235. Alternatively, a bend in the casing 140, 240 may be fully machined in the casing 140, 240. It is also contemplated that fabrications associated with the present invention may consist of simply bending the casing 140, 240. The bending in the casing 140, 240 would provide directional force for directional drilling with the casing 140, 240.

[000144] Figure 55 shows yet another alternative representation of a sliding operation associated with the present invention. In this embodiment, no bend is introduced into the casing as shown in Figures 14 and 15, and no eccentric pads 285 are located on the outer diameter of the casing as shown in Figure 15. Instead, in the embodiment of Figure 55, there is a or more fluid deflectors (nozzles) 475 on one side of a soil removal joint 350 operatively attached to a lower end of a casing 440 and angled outward with respect to the vertical axis of the casing 440, which may include a casing section or a casing string which consists of a whole range of casing parts. As shown and described in connection with Figures 14-15, a fluid deflector 475 is formed through the casing 440 and the soil removal joint 450, which is preferably a cutting device such as a drill bit. The soil removal link 450 can be a two-center crown, an expandable crown, a drillable cutting device, or something similar, depending on the application area. The liquid deflector 475 is inclined and at an angle in the direction where it is desired to divert the wellbore, or in the wellbore's prioritized direction. The liquid deflector 475 is largely similar to the liquid deflectors 175 and 275 respectively in figures 14 and 15. As noted in the embodiment shown in Figures 14 and 15, any number of liquid deflectors 475 may be used in the present invention.

[000145] As in embodiments shown in Figures 14 and 15, a float assembly group 415 and the landing seat 445 for an inspection tool (not shown) can be located within the diversion device 410.1 and with the float assembly 415 largely corresponding to the float assemblies 115, 215 shown and described in connection with Figures 14 and 15, the above description of the float assemblies 115, 215 in Figures 14 and 15 and their operation will apply equally to the float assembly 415 in Figure 55. Similarly, in that the landing seats 45, 145, and 245 in figures 13, 14, and 15, respectively, largely correspond to the land seat 445, the above description of the land seats 45, 145, and 245 and their operation will apply equally to the representation in figure 55.

[000146] In a preferred embodiment, the diversion device 410 includes an array of fluid deflectors or nozzles 475 grouped together on one side of the cutting device 450. Figure 57 illustrates a particular preferred embodiment, which includes three fluid deflectors or nozzles 475A, 475B, and 475C throughout the casing 440 and the cutting device 450 in order to preferably control the fluid flow into the formation. The liquid deflectors 475A, B, and C can point straight down, where the axes of the liquid deflectors 475A, B, and C are parallel to the axis of the cutting device 450. Another alternative is that the liquid deflectors 475A, B, and C can be placed at an angle radially outward from the cutting device 450, so that the axes of liquid deflectors 475A, B, and C are at an angle when it is an angle associated with the axis of the cutting device 450.1 an embodiment, one or more liquid deflectors 475A, B, 'and C may be at an angle, while the rest of the liquid deflectors 475A, B, and C may be straight. In a preferred embodiment, the vertical axes of the liquid deflectors 475 A, B, and C are at angles, approx. 30 degrees radially outward from the vertical axis of the cutting device 450.

[000147] During operation, the diversion device, to form a diverting wellbore, can alternately be jet drilled by flowing fluid through the casing 440 and into the fluid deflector 475 while the casing 440 is lowered into the formation, and rotated by rotating the entire casing 440 within the formation . During jet drilling of the fluid through the deflector 475, fluid through the deflector 475 will form a path for the diversion device 410 in the formation in the same manner as described above in connection with the fluid deflectors 175, 275 as shown and described in connection with Figures 14 and 15. With in other words, the fluid flows into the area of the formation that has the least obstruction, and the angular orientation of fluid deflector 475 will drive the fluid outward from the casing 440 into the formation at the angle in the priority direction associated with 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 such that the casing 440 moves through the path of least resistance to form a diverting wellbore path.

[000148] After the casing 440 has reached the desired depth within the formation, a physically modifiable binder, such as cement, may be flowed through the casing 440 to harden the casing 440 within the wellbore, in the same manner as described in connection with curing of the casing 140, 240 in Figures 14 and 15, using the float assembly 415. After the inspection tool has optionally been withdrawn, which may optionally reside within the landing seat 445, if the float assembly 415, the landing seat 445, and the cutting device can be drilled, the float assembly 415, the land seat 445, and cutting device 450 is drilled through by a trailing cutting device, for example, a trailing cutting device located on a trailing drill string or a trailing casing. If the components are drilled through by a subsequent cutting device on a subsequent casing, the additional casing can then be hung from the casing 440 (preferably on a lower end of the casing 440) and optionally drilled with a binder that can be changed physically inside the wellbore. This process can be repeated as desired by drilling and casing the wellbore to a full depth. The additional casing strings are inclined at an angle relative to the vertical axis of the casing 440 due to the deflection of the casing 440.

[000149] In a prioritized operation on the fabrication shown in Figure 55, casing 440 may alternately be jet drilled and/or rotated to form a wellbore within the formation. To form a diverting wellbore, the rotation of the casing 440 is stopped and an inspection operation is performed using the inspection tool (not shown) to determine the location of one or more fluid deflectors 475 within the wellbore. Filling (Stoking) can also be used to keep track of the liquid deflector(s) 475, and this method is described in connection with Figure 31 (see below).

[000150] Once the fluid deflector(s) 475 within the wellbore have been determined, the casing 440 is rotated, if necessary, to direct the fluid deflector(s) 475 in the desired direction where the casing 440 can be diverted. Fluid then flows through casing 440 and fluid deflector(s) 475 to form a profile (also called a "cavity") in the formation. The casing 440 can then continue to be jet drilled into the formation. When desired, the casing 440 can be rotated, forcing the casing 440 to follow the hollow shape of the formation. The locating and searching for the fluid deflector(s) 475, flow of fluid through the fluid deflector(s) 475, and further jet drilling and/or rotation of the casing 440 into the formation can be repeated as desired to cause the casing 440 to divert the wellbore in the desired direction within the formation .

[000151] Another alternative embodiment associated with the present invention consists of completing a prodding operation which must directionally drill the casing 440 into the formation and expand the casing 440 during a single pass of the casing 440 into the formation, such as shown in Figures 56A and 56B. In addition, cementing of the casing 440 into the formation can optionally be performed simultaneously on the casing 440 into the formation. Figures 56A-B show the diversion device 410, including casing 440, soil removal joint or cutting device 450, one or more fluid deflectors 475 (which may be a whole series of fluid deflectors arranged as shown and described in connection with Figure 57), and the landing seat 445 in Figure 55.

[000152] Additional components of the embodiment of Figures 56A and 56B include an expansion tool 442 capable of performing radial expansion of the casing 440, preferably an expansion cone 442; a barrage dart 486; and a dart seat 482. The expansion cone 442 may have a larger outer diameter at the upper end than at the lower end, and preferably slopes radially outward from the upper end to the lower end. The expansion cone 442 can be mechanically and/or hydraulically actuated. The locking dart 486 and the dart seat 482 are used in a cementing operation.

[000153] During operation, the diversion device 410 is lowered into the wellbore where the expansion cone 442 is located by alternating jet drilling and/or rotation of the casing 440, preferably by encouraging the casing 440 according to the prioritized method described in connection with Figure 55. Then, a setting tool 425 introduced into the casing 440. A physically changeable binder, preferably cement, is pumped through the setting tool 425, preferably an inner string. Cement flows from the surface into the casing 440, out of 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 is sealed on the dart seat 482. The dart 486 stops flow from exiting past the dart seat, thereby forming a liquid tight seal. Pressure applied through the inner string 425 may help urge the expansion cone 442 upward to expand the casing 440. In addition to or instead of the pressure through the inner string 425, mechanical pull on the inner string 425 helps to urge the expansion cone 442 upward. .

[000154] Instead of using the check valve 486, a float valve 415 as shown and described in connection with Figure 55 is used to prevent backflow of cement. The locking dart 486 is ultimately secured onto the dart seat 482, preferably by means of a locking mechanism.

[000155] Insertion tool 425 may be any extraction tool. Preferably, extraction of the expansion cone 42 involves the engagement of a longitudinally threaded bit through the expansion cone 442 with a lower end of the setting tool 425. The setting tool 425 is then mechanically pulled up to the surface through the casing 440, taking the associated expansion cone 442 with it. Alternatively, the expansion cone 442 is moved upward due to fluid pumping, down through the casing 440 to be able 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 will push against the inner surface of the casing 440, thus radially expanding the casing 440 as the expansion cone 442 moves upward toward the surface. Accordingly, the casing 440 is expanded to a larger internal diameter along its length as the expansion cone 442 is drawn out to the surface.

[000156] Preferably, expansion of the casing 440 is performed before curing of the cement takes place to harden the casing 440 within the wellbore, such that the expansion of the casing 440 squeezes the cement into the remaining voids in the surrounding formation, which will eventually result in better sealing and stronger cementation of the casing 440 in the formation. Although the above operation was described in connection with cementing the casing 440 inside the wellbore, expansion of the casing 440 by the expansion cone 442 in the method can also be performed when the casing 440 is hardened inside the wellbore in a different way than with cement.

[000157] As mentioned in connection with the preparation in Figure 55, the cutting device 450 can be drilled through by a subsequent cutting device (possibly attached to a subsequent casing) or it can be pulled out from the wellbore, depending on which type of cutting device 450 is used (for example , expandable, drillable, or two-center crown). Regardless of whether the cutting device 450 is extendable or drillable, the subsequent casing can be lowered through the casing 440 and drilled to a further depth within the formation. The subsequent casing can optionally be cemented inside the wellbore. The process can be repeated with additional casing strings.

[000158] Figure 16 shows a diversion device 310 drilled into a formation 320 to form a wellbore 330. The diversion device 310 includes an upper casing 340, in addition to 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 device 350 attached to the lower end. At least one nozzle 355 passes through the lower end of the lower casing 341 in addition to the first cutting device 350. At least one nozzle 355 enables fluid circulation between the casings 340, 341 and the wellbore. 330.

[000159] Diverter assembly 310 also includes an elongated connection 391, which is a collar used to attach the upper and lower casing strings 340 and 341 to each other. An upper part of the elongated connection 391 is attached to a lower part of the upper casing 340 through a threaded connection 342. Similarly, a lower part of the elongated connection 391 is attached to an upper part of the lower casing 341 by means of a threaded connection 343. The elongate connection 391 has a second cutting device 395 located at the very outermost part. Alternatively, only a casing (not shown) may have a second cutting device 395 located therein, which is not necessarily secured by a threaded connection. The outer diameter of the second cutting device 395/elongate connection 391 is larger than the outer diameter of the first cutting device 350. The second cutting device 395 extends along a substantial part of the length of the elongated connection 391, and even along the lower portion on the elongate connection 391 so that the cutting device 395 cuts into 320 as the diversion device 310 is progressively forced downward to form the wellbore 330. The second cutting device 395 has hole-opening blades which increase the inner diameter of the upper part of the wellbore 330.

[000160] During operation, the diversion device 310 is urged into the formation 320 by the downward axial force applied from a surface 305 on the wellbore 330. The elongated connection 391 on the diversion device 310 enables two casings 340 and 341 to be threaded together at the well site , so that the diversion device 310 does not need to be pre-fabricated on the casing 340 or 341. As another alternative, the second cutting device 395 can be pre-fabricated on the casing string (not shown). As described above in connection with the other embodiments, pressurized fluid is introduced into the diversion device 310 through the inner diameter of the upper casing 340 while the casing 340, 341 penetrates the formation 320 to form the wellbore 330, and then fluid flows into the the lower casing 341, through at least one nozzle 355, up through a second annulus 389 between an inner diameter of the wellbore 330 and an outer diameter of the lower casing 341, up through a first annulus space 390 between the inner diameter of the wellbore 330 and a outer diameter of the upper casing 340, and to the surface 305 of the wellbore 330.

[000161] As the diversion device 310 is moved axially downward through the formation 320 and the fluid is circulated, the first cutting device 350 cuts into the formation 320 to form a lower portion of the wellbore 330 approximately corresponding in diameter. In the same way, the second cutting device 395 will simultaneously cut into the formation 320 to form a lower part of the wellbore 330 approximately corresponding to the diameter. The outer diameter of the upper part of the wellbore 330 is larger than the outer diameter of the lower part of the wellbore 330 due to the difference between the diameter of the first cutting device 350 and the second cutting device 395.

[000162] Due to the difference in diameters between the upper and lower parts of the wellbore 330, the first annular region 390 between the outer diameter of the upper casing 340 and the inner diameter of the upper part of the wellbore 330 is larger than the second annular region the space 389 between the outer diameter of the lower casing 341 and the inner diameter of the lower part of the wellbore 330. The axial movement is stopped when the diversion device 310 reaches its desired depth in the wellbore 330.

[000163] 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 device 395, so that a larger diameter clearance exists on the upper part of the wellbore 330 than on the lower portion of the wellbore 330. The larger diameter clearance allows gravity to cause the casing to yield in one direction. The direction in which gravity causes the casing to yield is illustrated by the arrows located 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 device 395. A force in the opposite direction caused by the frictional resistance of the formation 320 is shown by the arrow perpendicular to the axis of the first cutter 350. The effect of the force shown by the arrows in Figure 16 is that the upper casing 340 moves laterally through the first annular space 390 while remaining generally anchored to the lower portion of the lower casing 341 of the second annular space 389 so that the diversion device 310 forms an angle in the priority direction. The second cutting device 395, or the additional drill bit grinding (dressing) on the outer diameter of the casing 340 and/or 341, consequently creates a larger void in the upper part of the wellbore 330 than in the lower part of the wellbore 330, which simplifies lateral movement of the casing 340 in the priority direction to create a derived path for the wellbore 330.

[000164] Again, an inspection tool (not shown) placed in a landing seat (not shown) as described above can be used to determine whether the diversion device 310 is bent in the desired direction at the desired angle. When the diversion device 310 has been diverted into the desired angle, the first and second casings 340 and 341 are cemented in place by means of a curing operation as described above. All of the components located within the inner diameter of the casing 340 are preferably made of a drillable material so that they can be drilled through after the curing operation so that the inner diameter of the casing 340 remains substantially hollow for subsequent downhole operations. Subsequent casings (not shown) are then driven into the wellbore 330 and suspended from the existing lower casing 341. The subsequent casings are inclined in the desired direction at the increasing angle in that they are largely consistent with the angle of the original casings 340 and 341.

[000165] Figure 17 shows an alternative embodiment of a diversion device

associated with the present invention. Diverting device 1310 is largely similar to diverting device 310 which is shown and described in connection with Figure 16; and therefore corresponding parts will not be described again here. The production shown in Figure 17 is different from the production shown in Figure 16 in that instead

because the concentric stabilizer which functions as the second cutting device, an eccentric stabilizer 1395 placed asymmetrically on one side of the outer diameter of the casing 1340,1341 adds additional directional force to the diversion device 1310.1 the description associated with the diversion device 1310 shown in Figure 17, stabilizer 1395, which preferably a 1 blade contour sharp bean kick pad, cause the upper portion of the casing 1340 to be positioned at an angle in the opposite direction from the eccentric stabilizer 1395. As an additional directional force acting in the same direction as the stabilizer 1395 tilts the casing 1340,1341, fluid deflector 1355, or a perforation in the cutting device 1350 set at an angle in relation to the vertical, can also be used to deflect the wellbore's 1330 trajectory further in a prioritized direction at an angle in relation to the vertical axis of the casing.

[000166] During the operation of the embodiments associated with Figures 16-17, a two-step process may be used. First, oriented jet drilling through one or more fluid deflectors (crown nozzles) 1355 can be achieved to establish an initial slope and direction on the casing. The casing 340 and 341, 1340 and 1341 may then be drilled further in a rotary fashion into the formation using the second cutter 395, 1395 to build the angle. In order to drill in a rotary fashion, the entire casing 340 and 341, 1340 and 1341 must be rotated while the casing is lowered into the formation 320, 1320. Using this two-step process, the more efficient rotary drilling method can be used to build up the angle on wellbore 330,1330.

[000167] Finally, Figures 18-20 illustrate an apparatus and method that can be used with a diversion device 510 to drill through the inner diameter of the diversion device 510 and clear obstructions so that additional casing strings (not shown) can be hung from the diversion device 510 after the original the derivation. The apparatus and method of Figures 18-20 may be used with any of the above embodiments to remove obstructions on the diversion device located within the inner diameter of the casing string after the casing string has been cured within the wellbore. Referring to Figure 18, it is shown that the diversion device 510 includes a casing string 540 with a second cutting device 595 located on the outer diameter. The casing string 540 is advanced into a formation 520 to form a wellbore 530. The inner diameter of the casing string 540 has a drillable joint 521 attached thereto, which is connected to a drilling device 522 by means of releasable connections 506. The releasable the connections 506, which are preferably shearable connections, are used to secure the diversion device 510 to the drilling device 522 torsionally and axially.

[000168] Drilling device 522 includes a drill string 523 with a first cutting device 550 associated with the lower end. The first cutting device 550 is smaller in diameter than the second cutting device 595, so that the second cutting device 595 has hole-opening blades that enlarge the inner diameter of the upper part of the wellbore 530. The first cutting device 550 has a cutting device 551 attached to the lower end, with at least one side parallel to a wellbore 530, and with the rear side 526 at an angle from the wellbore 530. The first cutting device 550 has at least one nozzle 555 which enables fluid to flow into and from a formation 520. The threads are preferably located on an upper end of the drill string 523 on the inner diameter.

[000169] The operation of the diversion device 510 and the drilling device 522 is shown in Figures 18-20. Figure 18 illustrates diversion/drilling assembly 510/522 during insertion of casing string 540. The diversion assembly 510 with the drilling assembly 522 attached thereto is pushed down axially into the formation 520 to form the wellbore 530. The diversion/drilling assembly 510/522 can also be rotated from a surface 505 of the wellbore 530 if it is desired to drill through the formation 520. The first cutting device 550 drills into the formation 520 due to the pressure placed on the casing string 540, which is transmitted to the drilling device 522.1 during the introduction of the casing string 540, forms the first cutting device 550 on drilling device 522 initially part of the wellbore 530 on a first diameter. The second cutting device 595 enlarges the diameter of the wellbore 530 on the part of the wellbore 530 into which it is forced, since the second cutting device 595 is larger in diameter than the first cutting device 550. Accordingly, the first annular space is the space 590 between the outer diameter of the casing string 540 and the inner diameter of the wellbore 530 larger than the second annulus 589 between the outer diameter of the drill string 523 and the inner diameter of the wellbore 530. The second cutting device 595, or the additional grinding on the outer diameter of the casing string 540, consequently creates a larger empty hole in the upper part of the wellbore 530 than in the lower part of the wellbore 530, which facilitates lateral movement of the casing string 540 into the priority direction to create a diverted 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 cause the wellbore 530 to flush e mud and other substances out of the casing string 540 through at least one nozzle 555 in the cutting device 550, outside the drill string 523 and the casing string 540, and up to the surface 505.

[000170] After the diversion/drilling device 510/522 is drilled into the desired depth in the wellbore 530 where the casing string 540 is to be diverted and drilled, a work string 503 or other type of extraction tool is lowered into the inner diameter of the casing string 540 (the work string 503 shown in Figure 19). The work string 503 pulls the drill string 523 using a draw tool profile on the lower end, preferably external threads 502 of the work string 503, which in a threaded manner engages internal threads 501 of the drill string 523.

[000171] Figure 19 illustrates the next step in operation involving the diversion/drilling device 510/522. The work string 503 is pulled up axially from the surface 505 to trigger the releasable connection 506. The releasable connection 506 is preferably cut off.. As a result of the tripping, the drill string 523 becomes movable axially and rotationally in association with the diversion device 510. The drilling device 522 is then pulled upwardly and rotated through the wellbore 530 by means of the work string 503. The cutting device 551 on the rear side 526 of the first cutting device 550 contacts the lower end of the drillable link 521 and the part of the releasable connection 506 that remains on the drillable link 521.

[000172] As seen in Figure 20, the cutting device 551 will drill completely through the drillable joint 521 and the remaining portion of the releasable connection 506 so that the drillable joint 521 and the releasable connection 506 are largely destroyed. The inner diameter of the casing string 540 is therefore left largely unobstructed so that wellbore operations can be performed or additional casing strings (not shown) can eventually be hung from the casing string 540. The drilling device 522 is then removed from the wellbore 530 by the work string 503.

[000173] Finally, the drill pipe string 540 is bent from surface 505 to one side at an angle. Due to the larger first annular space 590 on the upper part of the casing string 540, the casing string 540 is attached to the lower end but moves through the first annular space 590 on the upper part so that the casing string 540 is tilted at an angle. The additional casing strings can then be hung from the casing string 540 at the angle where the casing string 540 is inclined, which enables the wellbore 530 to deviate in the desired direction at the desired angle.

[000174] In the embodiments shown in Figures 13-20, the float assembly may include, but is not limited to, the following: a check valve, a poppet valve, a poppet valve, or any other type of one-way valve. Drillable material used to form the float assembly may include, but is not limited to, one or more of the following: aluminum, plastic, metal, cement, or a combination thereof.

[000175] Further, in any of the embodiments shown in Figures 13-20, the cutting structure may be a drillable bit or an expandable bit locked into the casing. For an example of an expandable crown suitable for use in the present invention, see U.S. Pat. Patent Application Publication No. 2003/111267 or U.S. Patent Application Publication No. 2003/183424, both of which are incorporated here in their entirety.

[000176] Diversion devices associated with the present invention and methods of their use enable effective diversion of a wellbore in one direction by diverting a casing string into the wellbore. Devices and methods are easy to build and enable diversion of the wellbore to be carried out while drilling with casing in an underground wellbore takes place. Accordingly, devices and methods associated with the present invention will assist in preventing unwanted cutting through of valuable underground wellbore.

[000177] The diversion device in Figures 13-20 used for prodding may be used as the outer casing 185 as shown in Figure 1, while the inner casing 195 may be any of the designs shown in Figures 1-12. In this manner, referring to Figure 1, the system 100 is jet drilled and/or rotated to sink the outer casing 185 into the soil formation 112 to the desired depth to form a diverting wellbore. Then, the releaseable connection between the inner casing 195 and the outer casing 185 is released, and the inner casing 195 is jet drilled and/or rotated, and the drilling system 157 can also be used to drill the inner casing 195 to the desired depth within the formation 112 while tilting continues in the direction and angle of the wellbore. The drilling system may include any of the embodiments shown in

Figures 1-12.

[000178] In most of the preferred embodiments of Figures 13-20, the casing is alternately rotated and/or sunk or jet drilled into the formation. Rotation and jet drilling help achieve the desired path in a wellbore.

[000179] In conventional drilling operations, hydraulic horsepower is transferred to the cutting device through one or more highly restrictive orifices or nozzles (commonly called "crown nozzles") located in the cutting device. The nozzles are located in the mass of cutting devices closest to the bottom of the wellbore. The function of the nozzles is primarily to pierce the soil formation with a "jet drilling effect" to facilitate formation of the wellbore, and then to bring the wellbore fragments up to the surface through the annulus between the wellbore and the casing. Additional functions associated with nozzles and fluid flows through them include cleaning of the cutting device, cooling of the crown cutting tools, and cleaning at the bottom of the wellbore. In order for the nozzles to be able to perform this function, the horsepower associated with fluid flow through the nozzles must be large during jet drilling. Due to the high horsepower associated with hydraulic fluid moving through the nozzles during jet drilling, the nozzles are subjected to very high erosion caused by pressure drop in drilling fluid across the nozzles (for example, from 500 to 3000 psi) (34.47 bar to 206.8 bar ) and high fluid velocity through the nozzles (for example, from 200 to 800 ft/s)(60m/s to 244m/s).

[000180] The necessary large flow rate of fluid through the nozzles to perform an adequate jet drilling operation requires that the nozzles be made of materials that allow the nozzles to be sufficiently hard and strong to resist erosion due to fluid through the nozzles. Therefore, a hard and strong material such as tungsten carbide and/or ceramic is usually used to jet drill into the formation with a drill string in conventional drilling operations, as nozzles made from one or more of these materials can last for thousands of hours without suffering fatal damage from erosion. Drilling with casing operations, however, such as those shown in Figures 1-22, may require the nozzles to be drillable, and the current ceramic and tungsten carbide nozzles used for jet drilling in the drill string are not drillable.

[000181] Drilling with casing operations may require the same fluid intensity, while jet drilling and/or rotation of the casing is required when drilling fluid is circulated in the drill string while drilling is in progress. However, the amount of time that fluid intensity must be maintained during drilling may be less for drilling with casing operations than in traditional drilling operations.

[000182] In the embodiments associated with the present invention shown in Figures 1-20, an expandable cutting device or a drillable cutting device may be used. An alternative embodiment may include a drillable cutting device, optionally including drillable nozzles. Figure 21 shows a drilling process through a drillable cutting device 1615 such as a drill bit or a drill shoe operatively attached to a casing 1610. The drillable cutting device 1615 has drillable nozzles 1616. The casing 1610 is lowered into the soil formation 1605 to form a wellbore 1630 by rotating the casing 1610 and/or through jet drilling the casing 1610. After the casing 1610 has been sunk and/or drilled into the soil formation 1605 to the desired depth, the casing 1610 in one embodiment can be cured there using a binding material that can be physically changed such as cement (not shown).

[000183] As shown in Figure 21, a casing 1620 is lowered into the inner diameter of the casing 1610 while fluid F is introduced through the inner diameter of the casing 1620, out through nozzles 1626 in a cutting device 1625 in the casing 1620, and up to the surface. The cutting device 1625 may be, but need not necessarily be, drillable. The cutting device 1625 can, as an alternative, be expandable and can be pulled out from the well hole 1630.

[000184] Figure 22 illustrates the next step in a preparation of a method for drilling through a cutting device on casing. The casing 1620 is lowered and/or rotated through the casing 1610 in order to be able to drill through at least part of the cutting device 1615. The nozzles 1616 are preferably also drillable, as described below. Figure 22 shows the casing 1620 drilled to a further depth within the formation 1605. After the casing 1620 has been sunk to the desired depth within the formation 1605, the casing 1620 can be expanded in a production. If desired, the casing 1620 can also be cured in there using the binder that can be changed physically. Then the cutting device 1625 can be left in the wellbore 1630 or it can be drilled through with an additional casing (not shown) or with a drill string or another type of cutting device.

[000185] The present invention provides drillable nozzles for use while drilling with casing is taking place. In order for the cutting device 1615 to be drillable, the base material and the nozzle(s) of the cutting device 1615 must be soft enough to allow drilling through the subsequent casing 1620. However, a nozzle made from a sufficiently soft material used for drilling with casing may only last a few hours under intense fluid erosion due to jet drilling. Although enlarging the nozzle diameter to reduce fluid velocity through the nozzle helps increase nozzle life, this design will remain problematic in that the fluid velocity through the nozzle(s) may be so reduced that the casing can no longer adequately drill through the formation in the course of the jet drilling process.

[000186] Figures 23A-23B, 24A-B, and 25-29 show embodiments associated with the present invention of a drillable nozzle, one or more of which may be used in any of the embodiments in Figures 1-22. The nozzles shown in Figures 23A-23B, 24A-B, and 25-29 can be inserted into the cutting devices of Figures 1-22 to provide a fluid path from the inner diameter of the casing into the wellbore. The drill bit breaks up into parts, preferably fragments or "wellbore fragments", which flow up to the surface using drilling fluid through the casing (not shown) used to drill through the drill bit. The drillable nozzles of Figures 23A-23B, 24A-B, and 25-29 are drillable while remaining sufficiently devoid of erosive deconstruction that will enable functional jet drilling to be achieved through the nozzles with drilling fluid or any other fluid introduced into the nozzles .

[000187] In the fabrication shown in Figures 23A and 23B, the drillable nozzle 1700 is fabricated from hard, brittle and resistant material. Examples of base materials that may be used to form the drill die 1700 include, but are not limited to, tungsten carbide, ceramic, and polycrystalline diamond (PDC). Figure 23B shows the first end 1751 of the nozzle 1700, as the liquid. F flows through during a drilling with a casing operation. While drilling with the casing attached to the cutting device having at least one drillable nozzle 1700, fluid F will flow through the casing, into the first end 1751, through a drill 1761 located within the nozzle 1700, and out through a second end 1741 of the nozzle 1700 (shown in Figure 23A), and then up through an annulus between the casing and the wellbore (or another casing placed around it) to the surface.

[000188] The drillable nozzle 1700 has one or more stressed parts, particularly shown as one or more stressed notches 1710 in Figures 23A-B. Preferably, the stressed notches 1710 have been placed within the outer diameter of the nozzle 1700 and are at least partially flush to the surface of the nozzle 1700. The stressed notches 1710 will preferably extend along the length of the nozzle 1700 coaxially with the bore 1761 of the nozzle 170. however, it is assumed that the stressed notches 1710 may extend only a portion of the length of the die 1700. The stressed notches 1710 provide a stress point which will cause the die 1700 to break into pieces or fragments when drilling is in progress with a trailing casing, a drill string, or other type of cutting device. Although there is no requirement for use in the present invention, a prioritized manufacture will contribute to the notches 1710 being generally placed at regular intervals along the outer diameter of the nozzle 1700. The notches 1710 are preferably relatively narrow sections through the length of the nozzle 1700.

[000189] An o-ring recess 1705 may occur within the outer diameter of the nozzle 1700 mass around the periphery for placement of an o-ring (not shown) there to seal the nozzle 1700 within a mass of the tool where the nozzle 1700 is located, such as a cutting tool (not shown). In one embodiment, an aggregate material 1715, preferably an extrudable material, such as epoxy or vulcanized rubber, is placed at least partially within the notches 1710 when the notches 1710 extend the entire length of the die 1700 so that the o-ring will seal the o-ring cavity recess 1705.

[000190] Figures 24A and 24B illustrate another embodiment of a drillable nozzle 1800. A first end 1851 of the nozzle 1800 is shown in Figure 24B, while a second end 1841 of the nozzle 1800 is shown in Figure 24A. When the drillable nozzle 1800 is placed in a cutting tool (not shown) operatively attached 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 other end 1841, then up through the annulus between the casing and the wellbore or between the casing and another casing placed inside the wellbore all around.

[000191] The fabrication shown in Figures 24A and 24B is substantially the same as the fabrication shown in Figures 23A and 23B, except for the following aspects. The stressed notches 1810 extend only through part of the nozzle 1800, coaxially with the drill 1861. The notches 1810, which are again at least partially flush to the surface of the nozzle 1800, are interrupted along at least part 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 will in any case be at the o-ring recess 1805, (sic) and eliminates the need to fill the notches 1810 with aggregate materials 1715 as in Figures 23A-B. An additional difference between the nozzle 1700 and the nozzle 1800 is that the notches 1810 should preferably be significantly wider than the notches 1710.

[000192] In the embodiments of Figures 23A-B and 24A-B, nozzles 1700 and 1800 provide long life to the weigher, as well as enable high flow rates for fluids so that the fluids can pass through the cutting device operatively attached to the casing. At the same time, when the nozzles 1700 and 1800 are then drilled through by a cutting device placed on a casing or drill string, the broken nozzle part can be circulated to the surface by means of an annulus between the subsequent casing or drill string and the wellbore.

[000193] Figures 25-28 show nozzle assemblies that may be used in a drillable cutting device operatively attached to the casing. Figures 25 and 26 show extended flow pipe 1910, 2010 of medium thickness and substantially uniform internal diameter or bore along each length. Each of the flow tubes 1910, 2010 represents a part of the nozzle assemblies 1900, 2000. Figures 27 and 28 show profiles of relatively thin flow tubes 2180, 2280, where each of them represents a part of the nozzle assemblies 2100, 2200.

[000194] In the embodiment associated with the present invention illustrated in

Figure 25, the nozzle assembly 1900 includes a flow tube 1910 located within a nozzle holder 1920. The flow tube 1910 is generally tubular with a longitudinal drill extending therethrough. In addition, the flow pipe is 1910, which is

preferably made of a relatively hard material such as ceramic, tungsten carbide, or PDC, relatively thin (eg, with a limited thickness) as measured from an outer diameter to an inner diameter of the flow tube 1910) to facilitate the ability to drill the flow tube 1910 when a cutting device, such as a

soil removal joint attached to a casing or drill string, is drilled through the flow pipe 1910.

[000195] The flow tube 1910 has a substantially uniform internal diameter bore along its length to form a generally straight bore through the flow tube 1910. The generally straight bore of the flow tube 1910 maintains a minimum thickness along the length of the flow tube 1910, thereby enhancing the drillability of the flow tube 1910 with a subsequent cutting device, since each profile of the flow pipe 1910 except for a straight drill through it would require an increase in the material thickness perpendicular to the axis of the flow pipe 910. The material thickness perpendicular to the axis of the flow pipe 1910 is transferred to the subsequent cutting device in order to be able to drill through it . In addition, the internal profile of the flow tube 1910 formed by the generally straight bore will thereby potentially reduce erosion of one or more parts of the nozzle 1900 in that the fluid does not need to change direction due to obstructions within the bore as it flows through the nozzle 1900 .

[000196] The nozzle holder 1920, which is generally made of a relatively soft, drillable material such as copper or plastic, holds the flow tube 1910 therein. The flow pipe 1910 is preferably mounted within the nozzle holder 1920, which is a tubular mass with a longitudinal drill passing through it. The nozzle holder 1920 may include an installation and removal feature, such as slots 1940 shown in Figure 25 in an exit side surface 1970 of the nozzle holder 1920. The slots 1940 facilitate installation and removal of the nozzle assembly 1900 from a tool 1925.

[000197] 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 can be positioned as desired within the nozzle holder 1920 by moving the flow tube 1910 up or down (right or left as as shown in Figure 25) within the nozzle holder 1920. By moving the flow pipe 1910 up or down coaxially with the holder 1920, entry and exit points for the fluid are enabled (shown in Figure 25, as the fluid flow moves from left to right in the described assembly 1900 ) to be located as required, either near or away from areas that may be susceptible to fluid erosion, as a result of high fluid velocity and turbulence caused by the high flow rate of the fluid as the fluid enters or exits the flow pipe 1910 Additionally, moving the flow tube 1910 downward relative to the tool portion 1925 will allow the fluid to exit point of concern from the die assembly 1900 to be placed closer to the formation than a typical die design, and will consequently improve the efficiency associated with jet drilling through the die assembly 1900 to remove portions of the formation by enabling increased control of the exit standoff 1960 and entry standoff 1950. Exit standoff 1960 is the distance of the liquid flow through the flow pipe 1910 measured from between the exit side surface of the tool mass 1925 and the starting point of the liquid from the flow pipe 1910, while the entry standoff 1950 is the distance of liquid flow within the flow pipe 1910 measured from between the entrance side surface of the tool mass 1925 and the entry point of the liquid into the flow pipe 1910.

[000198] The nozzle holder 1920 is generally made of a relatively soft, drillable material such as copper or plastic. The material of which the holder 1920 is made is softer than the material of the flow tube 1910. In addition, the material of the flow tube 1910 is more susceptible to corrosion than the material of the holder 1920. The internal bore of the holder 1920 is profiled to produce a controlled fit over the outer diameter of the flow tube. 1910, where an opening remains 1947 between the flow tube 1910 and the holder 1920 which is preferably substantially filled with a suitable adhesive 1945 to hold the flow tube 1910 in the desired position within the holder 1920.

[000199] The holder 1920 is located within a nozzle profile 1965 in a tool mass 1925. The tool is preferably a soil removal member which can cut into a soil formation, and which is even better, a cutting device such as a drill bit or a drill shoe. The tool mass 1925 is preferably made of a relatively soft, drillable material such as copper or plastic. An outer surface of the holder 1920 has a sealing recess 1907 with a seal 1905 to prevent fluid flow across the interface of the outer surface of the holder 1920 and the nozzle profile 1965 on tool mass 1925. An external thread 1915 secures the nozzle assembly 1900 within the tool mass 1925.

[000200] An advantage is that the preparation in Figure 25 allows adjustment of entry and exit points away from the tool mass 1925, and creates a dead zone 1930 in the fluid flow where high velocities and turbulence do not exist and directs fluid away from the holder 1920 and the tool mass 1925 produced by it the soft, drillable material that is more susceptible to erosion due to fluid flow than the harder material of the flow tube 1910.

[000201] An alternative representation of the nozzle assembly 2000 associated therewith

the present invention is shown in Figure 26. The nozzle assembly 2000 is largely similar to the nozzle assembly 1900 shown and described in connection with Figure 25; and therefore equal parts are marked with equal numbers (the last two digits of the numbers are equal). The difference between the assembly 2000 and the assembly 1900 is that the entire nozzle assembly 2000, including the nozzle holder 2020 and the flow tube 2010, can be made of a soft, drillable material such as copper or plastic or of a non-drillable material (such as when used in a retractable cutting device instead of a drillable cutting device, as described below). This design makes it easier to manufacture a nozzle assembly 2000 in that the nozzle assembly 2000 can

made in one piece. No glue 1945 is necessary in the production in figure 26 as the nozzle assembly 2000 is in one piece. The fabrication shown in Figure 26 can be used for drilling applications when the flow control is such that drillable materials such as copper or plastic can be used while benefiting from the removal of localized turbulence from the tool mass itself 2025 due to a straight-boring flow pipe 2010. This design enables sleeve isolation of the inner diameter of the flow tube 2010 by braiding, shrink fitting, or some other type of suitable method of adding a resistant material, such as tungsten carbide and/or ceramic, where the thickness of the resistant material is not so great that it will take away from the process of drilling through the die. The resistant materials can be placed in layers to achieve increased resistance and flexibility.

[000202] The die assemblies 1900, 2000 shown in Figures 25-26 enable adjustment of the input and output standoffs 1950 and 2050, 1960 and 2060 by moving the flow pipe 1910, 2010 within tool mass 1925, 2025. The flow pipe 1910, 2010 can be moved towards in - and the starting point of the liquid from the flow pipe 1910, 2010 as desired.

[000203] Figures 27 and 28 further show the alternative construction of a nozzle assembly 2100, 2200. The construction shown in Figure 27 includes the nozzle assembly 2100, which includes* a nozzle holder 2120 and a flow pipe 2180. The flow pipe 2180 is a profiled sleeve through which liquid flows from a tool such as a cutting device attached to the casing inside the formation while jet drilling and/or drilling is in progress. In Figure 27, the liquid enters the flow pipe 2180 from the left side at the entry point of an exit point and exits the flow pipe 2180 at an exit point. An inner diameter of the flow tube 2180 at the entry point of the fluid is greater than an inner diameter of the flow tube 2180 at the starting 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 has the first inner diameter. The flow pipe 2180 will then converge at an angle over distance B to a second inner diameter, which is smaller than the first inner diameter. The second inner diameter is maintained over a distance along the flow pipe 2180 all the way to the starting point of the flow pipe 2180.

[000204] The flow tube 2180 is made from a relatively hard material such as ceramic, tungsten carbide, or PDC to limit erosion of the flow tube 2180, as described in connection with Figures 23A-B, 24A-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 device, as described above in connection with Figures 25-26.

[000205] A relatively soft, drillable material such as copper or plastic is used to form the nozzle holder 2120. The material of the flow tube 2180 is harder than the material of the holder 2120 and the tool mass 2125, and the material of the flow tube 2180 is more resistant to corrosion than the material on the holder 2120. The drillability of the soft material enables the nozzle holder 2120 to be of a greater thickness at the portion adjacent to the small diameter portion of the flow tube 2180 than the thickness of the other portions of the flow tube 2180. The inside diameter of the holder 2120 will therefore generally conform to the outer diameter of the flow tube 2180.

[000206] The nozzle assembly 2100 is placed in a tool mass 2125, which is preferably a soil removal joint such as a drill shoe or a drill bit. The tool mass 2125 is preferably made of a relatively soft (at least compared to the flow pipe 2180), drillable material such as copper, aluminum, cast iron, plastic, or a combination of these. The material of the tool mass 2185 may or may not be the same material as the holder 2120. A seal 2105 has been placed within a sealing recess 2107 formed in an outer diameter of the holder 2120 to prevent fluid from moving into the area between the inner diameter of the tool mass 2125 and the outer diameter of the holder 2120. Support threads 2115 are located between the tool mass 2125 and the holder 2120 to be able to connect the nozzle assembly 2100 to the tool mass 2125.

[000207] The nozzle assembly 2100 is characterized by an extended outlet. The extended exit is represented by an exit standoff 2160 which consists of the length of the flow tube 2180 extending past the end of tool mass 2125 from which fluid flows after exiting the flow tube 2180. An exit standoff 2160 diverts the flow turbulence into an area away from the nozzle holder 2120 and the tool mass 2125.

[000208] Figure 28 shows an additional representation associated with the present invention. The production shown in Figure 28 is largely the same as the production shown in Figure 27; and therefore the elements which are largely similar to Figure 27 which are in the "21" series have been labeled in Figure 28 as the "22" series. The difference between the embodiment in Figure 27 and the embodiment in Figure 28 is that the embodiment shown in Figure 28 not only includes the extended output in the form of an output stand-off 2260, but also includes the extended input in the form of an input stand-off 2250. The inlet stand-off 2250 is the length of the flow tube 2280 that extends past the end of the tool mass 2225 into which fluid flows after entry from the flow tube 2280. The extended entry of fluid through the flow tube 2280 provides an area of low turbulence at the side of the tool mass 2225 at the entrance. In addition to use in drillable applications, the embodiments in Figures 27 and 28 can all be used in non-drillable applications such as in expandable cutting devices when casing drilling is in progress.

[000209] Figure 29 shows a representation of a soil removal joint 1925 ("tool mass"), preferably a cutting device in the form of a drill shoe or a drill bit, which includes two nozzle assemblies 1900. The nozzle assemblies 1900 are shown, but one or more of the nozzle assemblies 2000, 2100 , 2200 can, as another alternative, be located within the tool mass 2125. The upper nozzle assembly 1900 shown in Figure 29 is oriented at an angle associated with the vertical axis of the casing connected to the tool, and will consequently illustrate use of the nozzle assembly 1900, 2000, 2100 , 2200 with directional drilling using jet drilling through a fluid deflector, or an oriented nozzle or jet drill, as shown and described in connection with Figures 14-15 and 17. Figure 29 is also demonstrated by referring to the lower nozzle assembly 1900 as shown in that figure as the nozzle assembly 1900, that 2000, 2100, 2200 can also be used for casing operations that do not involve prodding and directional drilling g.

[000210] In addition to use in drillable application areas, the above-mentioned products as shown in Figures 25-29 can also be used in a retractable cutting device when a retractable cutting device is used with the products associated with the invention shown in Figures 1-22, such as an expandable crown . The preparation in Figure 26 applies in particular to non-drillable nozzles, where protection of the tool mass 2025 at the entry and exit points is required, or when it is necessary to place the nozzle's point of departure closer to the formation.

[000211] Figure 30 is a cross section of the lower end of a cutting device having nozzles passing through it. In directional jet drilling, as shown and described in connection with Figures 14-15 and 17, one or more of the nozzles on the cutting device may be blocked to prevent fluid flow therethrough. The unobstructed nozzles will produce selective fluid flow from only a portion of the cutting device, so that fluid flow is asymmetrically introduced into the wellbore and forms a diverting path for the casing within the formation.

[000212] The alternative embodiments in Figures 53A, 53B, and 54 provide drill bit nozzles that are designed to resist irritating and erosive effects on jet-drilled drilling fluid, while also being suitable for subsequent drilling operations that aim to drill through the drill bit masses as the nozzles is attached to, and indeed the nozzles themselves. The embodiments in Figures 53A-B and 54 further provide a method for drilling a well hole, where the drilling method consists of what is commonly known as drilling with casing, and where subsequent drilling can be performed by a subsequent drill bit, without the requirement for removal of the former or first drill bit from the wellbore, and wherein the former or first drill bit includes nozzles.

[000213] Figures 53A-B and 5 show representations of a new and improved drill bit nozzle consisting of a mass which defines a through-bore, where the through-hole defines a passage for drilling fluid in use, where the surface of the through-hole within the mass has a relatively high resistance to erosion, and where the nozzle is characterized by the fact that the mass is largely made of a material or materials which enable the nozzle to then be drilled through by standard wellbore drilling equipment. Preferably, the bore has an enlarged concave portion at an intake side of the nozzle, which communicates with a small diameter cylindrical portion.

[000214] The nozzle mass can be made of two materials, where the surface of the through hole is made of the first material, where the relevant first material is of relatively thin construction and has good resistance to erosion, and where the rest of the nozzle mass has been made of another material which is easy to drill through. The first or surface material may be hard chrome. As another alternative, tungsten carbide or suitable alloys may be used, the suitability of which is evaluated based on their ability to withstand the erosive force of well fluid jet-drilled through the borehole.

[000215] The other material which generally forms the majority of the die mass is usually made of a softer metal, such as nickel, aluminum, copper or alloys. Preferably, the second material can be copper and the surface or the first material is hard chrome, where the hard chrome is added to the copper mass by means of electroplating.

[000216] As another alternative, a nozzle in accordance with the present invention may be made of rubber material. In this regard, it should be noted that although rubber is not usually a "hard" material, it nevertheless has a strong resistance to erosion. In addition, rubber materials can be easily drilled with subsequent drill bits. A nozzle in accordance with the invention can be made of one or more materials and need not be made entirely or even partially of metal. Polyurethane or other elastomers can also be used.

[000217] Referring first to Figures 53A and 53B, there is shown a drill bit nozzle 1. The drill bit nozzle 1 has been adjusted to engage threadedly with a drill bit mass (not shown) by means of the threaded parts 2. The nozzle 1 is provided with an annular mass 3 defining a through-passage or a through-bore 4. The through-bore 4 is formed with an inlet having a concave enlarged part 4a which communicates with a cylindrical small diameter part 4b leading to an outlet 7. The geometry associated with the through-hole 4 is such that well fluid is jet-drilled at high speed out of the outlet 7.

[000218] It is known in the invention that the nozzle bore 4 is intended to receive drilling fluid at high speeds and with high pressure differentials. Accordingly, the surface 5 of the through-hole 4 is made of a material suitable to withstand the irritating and erosive type of drilling fluid used. Not only must the surface of the through passage withstand the erosive force of the drilling fluid, but considering how close the nozzles are to the cutting surface of the drill bit, excessive wear can be caused if a non-resistant material is used as a result of the action of small rock particles and other debris cut out by the drill bit from the well formation. The erosive effect of rock particles within the drill bit nozzles is well known and documented. For this reason, the surface of the through-hole 4 is preferably produced from a hard material which, in an example in the production in figures 53A-B, is a hard chrome material. In another example, tungsten carbide can be used as a surface material.

[000219] The surface material will usually be chosen as a material capable of being combined with a softer, drillable material that will largely form the mass of the bit nozzle, except for the surface that has been mentioned hereinbefore. In the example in the manufacture illustrated in Figure 53A-B, the other material from which the nozzle is mostly made will be copper. Copper is chosen as a suitable material as surface coating of hard chrome can easily be added to the copper mass by means of electroplating. In addition, the cups are sufficiently soft to allow a subsequent drill bit to be drilled through the die mass.

[000220] In Figure 54, an alternative nozzle 12r is generally made of a single non-metallic material, preferably rubber. However, to enable the rubber nozzle 12 to be attached to a drill bit mass, the nozzle 12 must be 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 enable a subsequent drill bit to drill through it.

[000221] An advantage associated with the present invention will be clearly demonstrated from the method of application to the drill bit nozzle as shown in Figures 53A-B and 54 and described above, which enables drill bit carrying drill bit nozzles (Sic) to be left in a wellbore during the cementing of casing and then drilled through using standard downhole drilling equipment to enable the well to be expanded. It appears that the invention can overcome the difficulties associated with providing drill bit nozzles in such a way that their resistance would appear to be worn as a result of the erosive properties associated with the jet drilling fluid, while nevertheless allowing subsequent conventional or standard downhole drilling equipment will have the opportunity to drill through them.

[000222] When casing is driven into the formation, it is often practical to produce a casing string consisting of a series of casing sections. When the casing string is manufactured this involves rotating one casing section relative to another casing section in order to connect these sections together in a threaded manner. Many of the directional drilling tools described in the figures in the relevant application include inclined tools (eg, an eccentric stabilizer and/or a directional jet drill) located on the casing or inside the casing, the location of which must be tracked from the surface of the wellbore to enable the operator to maintain the direction and angle of the diverting wellbore while drilling with the casing is in progress. One method of tracking the position of the bevel tool on the casing consists of marking the position of the bevel tool. when the casing which has the bevel tool on it is first sunk into the formation ("stoking or scribing in the hole").("Filling and scribing the hole") Marking the position can be achieved by drawing a vertical chalk line along the casing as one casing section is threaded onto another. Then, when the marked casing section is lowered into the wellbore, the part of the marked casing section that still remains above the wellbore (for example, a spider on a drill deck) becomes the reference point for marking with chalk just after the next section of casing is threaded onto the casing string.

[000223] An additional method of tracking the position of the bevel tool, which can be used in addition to the scoring method, is achieved by the mechanism shown in Figure 31. A casing string 2300 which can be used in the present invention while jet drilling is in progress into the formation includes a casing part 2320 which has external threads 2321 threaded to a casing part 2330 with external threads 2331 with a collar 2315 with internal threads 2311 and 2312. A supporting torsion ring 2310 is located inside the collar 2315. The supporting torsion ring 2310 is an intermediate member located between the ends of needles 2331, 2321 of the casing parts 2330, 2320 to provide a stop mechanism to stop torsion of the casing parts 2330, 2320 at a particular time. The support torsion ring 2310 can be used to hold the chalk line when scribing in the hole is in progress so that the chalk mark does not become inaccurate in connection with the location of the bevel tool as the rotational position of the casing parts 2330, 2320 relative to each other changes.

[000224] Additional embodiments associated with the present invention provide generally improved methods and assemblies for drilling with casing (DWC). In contrast to prior methods, drilling assemblies according to the present invention are supported between an attachment point on the bottom of the casing and the contact point by one or more adjustable stabilizers. The stabilizers can have one or more adjustable support links that can be placed in a first (insertion) position which gives the stabilizer a sufficiently small outer diameter to be able to be driven through the casing with a drill assembly. The support links can then be placed in a second position which will give the stabilizer a sufficiently large outer diameter to have an inner wall of the wellbore to support the drill assembly during drilling.

[000225] Additional embodiments associated with the present invention provide directional power for directional drilling of the assembly on the casing instead of the BHA. In addition, embodiments associated with the present invention can reduce the required length of the rathole below the casing, thereby reducing the amount that the casing must be sunk into the rathole after the BHA has been drilled to the desired depth within where the casing is to be placed in the wellbore.

[000226] In various embodiments, the drill assemblies associated with the present invention can be adjusted to operate in either a rotary or a thrust mode. In some embodiments, in an attempt to reduce drilling time, an expandable crown with a higher removal rate than the conventional combination of an expansion drill and a pilot crown may be used. Although fabrications associated with the present invention may be particularly advantageous for directional casing drilling, some fabrications may also be used to benefit non-directional DWC systems. This type of production may not have the bent subassemblies shown in the following figures.

[000227] Figures 33A-D illustrate an example of a DWC system for directional drilling of a wellbore 4102 through a formation 4103 using a drill assembly, according to an embodiment associated with the present invention, consisting of a bottom hole assembly (BHA) 4200 attached to a portion on casing 4104. As illustrated, the drilling assembly generally includes at least one adjustable stabilizer 4202. In some embodiments, the adjustable stabilizer 4202 may be positioned to provide support for the BHA 4200 between a casing stop 4106 and an earth removal link or a drilling joint, such as an expandable bit 4204. Accordingly, the adjustable stabilizer 4202 can reduce the amount of drift on the BHA 4200, thereby improving directional control, increasing bit life, and increasing the formation removal rate.

[000228] As illustrated in some embodiments, the stabilizer may be placed above a tilt joint, such as a bent mounting group 4114 ("bent mounting group") used to tilt the BHA 4200 in the desired direction. The bent assembly assembly 4114 may be stationary or adjustable to tilt the crown surface 4204, typically from 0<2> to about 32 in conjunction with the centerline of the BHA 4200. As previously described, the bent assembly assembly 4114 may be integral with a downhole motor 4112. The number of adjustable stabilizers 4202 used in a system can depend on a number of factors, such as the weight-on-bit supplied to the BHA 4200, the length of the BHA 4200, the desired wellbore path, etc.

[000229] Although a conventional pilot bit and expansion drill may be used in some embodiments, the expandable bit 4204 will generally provide an increased removal rate and perform the same operations (eg, forming an expanded hole below the casing 4104, and making possible for the casing string to move forward with the wellbore). The increase in removal rate can be achieved by providing greater density in the cutting elements ("cutting density") in contact with the wellbore surface. For example, the cutting joints 4205 on the crown 4204 may include cutting elements arranged in a complete group (complement) with the hole profile to achieve an optimal penetration rate. An example of an expandable crown 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 associated with crown 4204 can be made of any suitable hard material, such as tungsten carbide or polycrystalline diamond (PDC).

[000230] The operation associated with BHA 4200 can best be described with reference to Figure 34, which illustrates a flowchart of exemplary operations 3300 for directional DWC, according to an embodiment associated with the present invention. At step 3302, a drill assembly (eg, BHA 4200) is driven down a wellbore 4102 through casing 4104, where the drill assembly has one (at least one) adjustable stabilizer 4202 and an expandable crown 4204. As illustrated in FIG: 33A, to drive BHA 4200 through the casing 4104, the support links 4203 of the stabilizer 4202 and the cutting links 4205 of the expandable crown 4204 can be placed in a first (insertion) position, where the stabilizer 4202 and the expandable crown 4204 each have an overall outer diameter smaller than the inner (drive) the diameter of the casing 4104. The BHA 4200 is generally run until a securing mechanism, such as a casing stop 4106, is abutted with a bottom portion of the casing 4104. At step 3304, the drill assembly is secured to a bottom portion of the casing 4104, for example, with the casing barrier 4106.

[000231] At step 3306, the crown 4204 is expanded to have an outer diameter greater than an outer diameter of the casing 4104. For example, as illustrated in Figure 33B, the cutting members 4205 of the expandable crown 4204 may be expanded into an open position . Generally speaking, the movement of the cutting joints 4205 between the retracted and extended positions can be controlled through the use of hydraulic fluid flow through the center of the expandable crown. For example, increasing hydraulic pump pressure (e.g., by increasing drilling fluid flow) may move the cutters 4205 into the extended position while decreasing hydraulic pressure may return the blades to the retracted position (e.g., for extraction of the BHA 4200 after drilling operations are completed, for crown replacement etc).

[000232] At step 3308, the stabilizer 4202 is adjusted for directional control of the drill assembly. For example, initially an outer diameter of the stabilizer 4202 may be adjusted from the first (insertion) position to a second position having a sufficiently large diameter to cause the inner walls of the wellbore 4102 to support the BHA 4200 while drilling ongoing. During the drilling process, as will be described in more detail below, the stabilizer 4202 can be adjusted to a third position (between the insertion position and the second position) to vary the under-measurement amount (eg, separation between the support joints 4203 and the inner walls on the wellbore 4102), in an attempt to control the trajectory of the hole.

[000233] Aids for adjusting the stabilizer 4202 may vary with different manufactures. For example, as illustrated in Figures 33A-33C, support links 4203 may be implemented as movable arms/blades that can be retracted to a first (insertion) position (Figure 33A), extended to a second position, and partially retracted/extended to third position (Figure 33C) to provide 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 links 4203 can be set edge to edge to give the stabilizer 4202 a smaller diameter during insertion. The support links 4203 may then be displaced (eg, by rotating one of the support links 203 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 links 4207 (shown in Figure 33D ) which can be adjusted between first, second and third position. As yet another alternative, the stabilizer 4202 may include an inflatable or mechanical support link (not shown), which may be actuated similarly to a packing member to adjust the stabilizer between first, second, and third (or more) positions.

[000234] In either case, adjustments to the stabilizer 4202 (between the various positions) can be made by any means, such as hydraulic means (similarly described above in connection with the expandable crown 4204), mechanical means , and electrical or electro-mechanical aids, etc. However, the stabilizer 4202 may be designed for use in rotary and/or thrust modes. For example, in push mode, the stabilizer 4202 will provide for string centering and prevent the BHA from leaning over to one side of the hole. For some embodiments, the stabilizer 4202 may include sensors that monitor relative movement of the casing 104 to enable the stabilizer 4202 to rotate with the casing 4104 or to slide as the casing 4104 is rotated to help control the direction of the hole. In either case, the stabilizer 4202 can prevent the BHA 4200 from yielding (and leaning to one side) when weight-on-crown is applied to the BHA 4200. By preventing diversion of the BHA 4200 within the wellbore 4102, the stabilizer 4202 can also reduce the amount of axial and lateral vibration.

[000235] As previously described, too much vibration, especially in the case of rotary vibration, can lead to less than optimal contact between the drill bit 4204 and the formation 4103, which leads to a reduced penetration rate and correspondingly increased drilling time, which in turn increases production costs. In addition, unusually high levels of vibration can lead to catastrophic overshoots that damage and/or destroy the various components of the BHA 4200.1 In an attempt to reduce vibration even further, the BHA 4200 can also have a flexible collar 4206 that can be designed to prevent vibration from being transferred from the flex assembly assembly 4114 to the upper portion of the BHA 4200 (eg, any portion above the flexible collar 4206). The flexible collar 4206 can be made of any flexible type of material capable of withstanding severe well conditions.

[000236] At step 3310, the drill bit 4204 is rotated to drill a hole having an outer diameter greater than the diameter of the casing 4104. As previously described, the fabrication of the BHA 4200 can be run in a rotary position or in a thrust position. In the rotating position, the drill bit 4204 can rotate with the casing 4104 and is controlled by a rotary steerable assembly (not shown) which has adjustable pads that can be used to "push away" the internal walls of the formation 4102 to adjust the deviation of the bit angle from center . In the push position, the drill bit 4204 can be rotated by a controllable well motor 4112 which typically provides a high rotational speed and high removal rate without having to rotate the casing 4104. When operated in either of these positions, the stabilizer 4202 provides centralization and prevents the BHA 4200 from leaning to one side in the hole, which gives better control over the trajectory of the hole.

[000237] At step 3312, the path of the hole is monitored. As previously described, the hole in conventional DWC systems can be controlled by geological indicators that are logged at specific points during drilling (logging while drilling or "LWD") using at least one LWD tool. Although this logging can be used to reconstruct and confirm the wellbore trajectory after drilling, this may be too late to make changes. Monitoring the path of the hole while drilling (Measuring While Drilling or "MWD"), manufacturing with this invention may allow changes to be made to the surface, e.g. by adjusting the weight of the drill bit, adjusting the angle of the bend assembly group, and/or controlling the motor 4112.

[000238] Additionally, as previously described, the stabilizer 4202 can be adjusted in response to trajectory monitoring. The support joints 4203 can e.g. is adjusted to create a separation between the stabilizer 4202 and the inner surface of the wellbore 4102. Separation between the stabilizer 4202 and the inner surface of the wellbore 4102 (as shown in Figure 33C) may allow the flex housing 4114 of the motor 4112 to lean more toward one side and thus increase the bending of the drill bit. Accordingly, the "undergauge" of the stabilizer 4202 may vary, for example in an attempt to control the bit deflection on the bit from center, for example to make relatively fine adjustments to the wellbore path 4103 when it is pulled out.

[000239] The wellbore trajectory 4102 can be monitored with MWD tool 4107. As shown, this can be placed anywhere on the BHA 4200. The MWD tool 4107 can generally be used to evaluate the wellbore trajectory 4102 in three-dimensional space as the wellbore 4102 is extended. Therefore, the MWD tool 4107 may typically include one or more sensors to measure the trajectory (eg, azimuth and inclination) of the wellbore, such as a steering sensor, accelerometer, magnetometer, or similar.

[000240] The MWD tool 4107 can of course also have sensors to monitor one or more well parameters, such as e.g. wellbore conditions (eg, pressure, temperature, wellbore trajectory, etc.) and/or geophysical parameters (eg, resistivity, porosity, sound speed, gamma rays, etc.). In some embodiments, the MWD tool 4107 can log such parameters which can then be retrieved on the surface. Therefore, the MWD tool 4107 can also perform the same functions as a conventional LWD tool. Regardless of whether these parameters are logged or whether the values are transmitted wirelessly to the surface in real time, measuring these parameters while drilling can save an extra trip down the wellhole only because such measurements.

[000241] Any telemetry method may be used to communicate between the wellbore trajectory (and any other parameters) monitored by the MWD tool 4107 and the surface of the wellbore 4102. Examples of suitable telemetry methods may include electronic methods (e.g., through a wireline or pipe with wire) and/or digitally encoded data transmitted to the surface as pressure pulses in a mud system using sensing devices that include, but are not limited to, one or more of the following: mud pulse telemetry device; mud pulse gyroscope device; gyroscopic telemetry device on the lead wire; gyroscopic telemetry electromagnetic device; gyroscopic telemetry acoustic device; gyroscopic telemetry lamp pulse device; magnetic dipole including single shot and telemetry; casing with wire as shown and described in accordance with U.S. Application Serial Number 10/419,456 entitled “Wired Casing” filed Apr. 21, 2003 and incorporated by reference in its entirety; and fiber optic scanning devices. Any combination of sensors and/or telemetry can be used in this invention. Whichever method is used, based on the monitored trajectory received at the surface, adjustments can be made at the surface (eg, adjusting the stabilizer 4202, the weight of the drill bit, the rotational speed, controlling the motor 4112 or the steerable rotary assembly, etc. ).

[000242] Therefore, operations 3308-3310 can be repeated to extend the wellbore to the desired length along a well-controlled path. Once the desired length has been achieved, the BHA 4200 can be pulled out of the wellbore. For example, the BHA 4200 can be withdrawn by loosening the casing lock 4106 and placing the stabilizer 4202 and an expandable drill bit 4204 back into the downstroke positions (as shown in Figure 33A) and by pulling the BHA 200 back to the surface through the casing 4104. The casing string 4104 can then extended into the recently drilled portion of the wellbore, for example by adding casing parts 4104 from the surface.

[000243] However, pulling out the BHA 4200 through the entire length of the casing 4104 may require a longer time where the formation around the newly drilled (and cased) portion of the wellbore may harden, making it difficult to advance the casing string 4104 afterwards. In some designs, therefore, before the BHA 4200 is fully pulled out, the BHA 4200 can only be partially lifted through the casing 4104 (e.g. enough so that the drill bit 4205 is at least partially inside the casing 4104). After the BHA 4200 is partially lifted, the casing 104 can be passed inside the newly drilled portion of the wellbore, for example by adding casing parts 4104 from the surface. Because it takes much less time to partially lift the BHA 4200 than to fully lift the BHA 4200 to the surface (as in pullout), the likelihood of the formation hardening before the casing 4104 is advanced is reduced. After the casing 4104 is advanced, the BHA 4200 can be fully withdrawn.

[000244] Although the adjustable stabilizer 4202 is shown in Figures 33A through 33D between the drill bit 4205 and the casing stopper 4106, in some embodiments, one or more adjustable stabilizers may be placed over the casing stopper 4106 instead of or in addition to the adjustable stabilizer 4202 For example, an adjustable stabilizer 4202 can be placed over the casing stopper 4106 to provide support for the casing 4104, which when used as part of the drilling assembly (including the BHA 4200), can be subjected to similar loading as the BHA 4200. In other words, the casing 4104 can be subjected to load on the drill bit and especially in cases of rotational operation, lateral and radial vibrations may occur. Additionally, although not shown, a drill assembly may include a BHA 4200 attached to a portion of casing that passes through another portion of casing (not shown) that is already casing the wellbore. For example, the BHA 4200 may be attached to a section of the expandable casing. After the wellbore has been extended with the BHA 4200, the expandable casing can be advanced and expanded as casing on the extended part of the wellbore. The BHA 4200 can of course be pulled out of the wellbore before the expansion takes place.

[000245] In another embodiment, the expandable drill bit 4205 can be replaced with a combination of a pilot drill bit and expansion bit. The making of this invention provides methods of assembly for improved drilling casing (DwC). By using an adjustable stabilizer, the drill assembly can be adequately supported and thus avoid excessive bending and vibration that usually occurs with conventional DwC systems. In addition, using MWD equipment, the wellbore trajectory can be measured in real time, which allows corrections to be made to the trajectory at the surface, which in turn increases the likelihood of the desired trajectory being achieved. Another embodiment may include closed-loop drilling to regulate the diameter of the adjustable stabilizer or motor bend angle, or a three-dimensional rotary steerable system. The closed loop control can be a microprocessor that is above the well or in the well.

[000246] Figures 35 and 36 show alternative representations of a system with directional drilling with casing. These disclosures provide methods and devices for drilling with a BHA releasably attached to the casing that allows for directional pressure so that the system can be placed directly on the casing instead of directly on the BHA.

[000247] Figure 35 shows casing 2404, with a BHA 2400 releasable fastener, which is attached to the inside diameter by a casing stopper 2406. Although the casing stopper 2406 is shown in Figure 35, any releasable fastener attached to the BHA 2400 to the diameter of the casing stopper 2406 contemplated for use in this invention. The casing detent 2406 performs a positioning function (described below) in addition to releasing the connected casing 2404 from the BHA 2400. To this end, one or more axial blades 2407 run radially from the body of the casing detent 2406 on the BHA 2400. In addition, one or more torque blades 2405, which are found below the axial blades 2407, radially from the main part of the casing stopper 2406. Torque blades 2405 can be found in any number. The same applies to the axial blades 2407. The axial blades 2407 and the torque blades 2405 are spring-loaded.

[000248] Casing 2404 consists of one or more casing parts. Figure 35 shows three casing parts 2404A, 2404B, and 2404C threaded together. The lower casing portion 2404C is threaded together with the middle casing portion 2404B with a casing coupling 2416. The casing coupling 2416 may have internal threads on the top and bottom to connect the lower portion of the middle casing portion 2404B to the upper portion of the lower casing portion 2404C. The upper casing member 2404A is connected to the casing member 2404B by a profile collar 2411. The profile collar 2411 may have internal threads at each end to connect each end to the external threads of the lower end of the upper casing member 2404A and to the upper end of the middle casing member 2404B. The profile collar 2411 has profiles 2413 which releasably attach the axial blades 2407 and profiles 2415 to it to be able to releasably attach the torque blades 2405.

[000249] When used to connect the BHA 2400 to the casing 2404, the BHA 2400 with the spring-loaded axial blades and torque blades 2407 and 2405 is passed through the casing 2404. When the blades 2407 and 2405 have reached the profiles 2413 and 2415 in the inner diameter of the profile collar 2411, the bias loading from the spring-loaded blades 2407 and 2405 causes the blades 2407 and 2405 to exit their respective profiles 2413 and 2415. The torque blades 2405 rotate a few degrees before snapping into the profile collar 2411. The axial blades 2407 prevent the BHA 2400 from transferring axially in relation to the casing 2404, and the torque blades 2405 prevent the BHA 2400 from rotating relative to the casing 2404. Although the profiles 2415 and 2413 are shown inside the profile collar 2411 in Figure 35, it is also contemplated that in this invention may be inside the casing 2404 itself to could release the axial blades and torque blades 2407 and 2405.

[000250] An upper portion of the BHA 2400, shown here as the upper position of the casing stopper 2406, has one or more packer elements 2417 on the outer diameter that seal an annulus between the BHA 2400 and the casing 2404. The packer elements 2417 should preferably be elastomeric to seal between casing 2404 and BHA 2400. Additionally, cups 2418, located above and below packer elements 2417, help seal the annulus between casing 2404 and BHA 2400. Packer elements 2417 and cups 2418 run radially from BHA 2400 circumferentially around the body of casing stopper 2406.

[000251] The upper end of the casing stopper 2406 has threads 2419, preferably internal threads and/or a fish profile that allows rings to attach to or around (see U.S. Patent No. 3,951,219, which is incorporated by reference in its entirety) to connect the BHA 2400 to the surface with a tubular body (not shown) so that the BHA 2400 can be withdrawn when desired. In addition, the upper end may have a GS profile. Possible forms of tubing that can draw up BHA 2400 include, but are not limited to, drill pipe, tubing, rod tubing, or wirelines. Beneath the casing stopper 2406 in the BHA 2400 is a resistivity assembly assembly 2420 that contains one or more resistivity sensors (not shown) used to take real-time or periodic resistivity measurements. Surrounding the resistivity assembly 2420 is a stabilizer 2422 extending radially from and preferably circumferentially around the BHA 2400. The stabilizer 2422 bridges the BHA 2400 and the casing 2404 and maintains the position of the BHA 2400 within the casing 2404 in a preferred axial position to stabilize the BHA 2400 in relative to casing 2404.

[000252] The resistivity assembly group 2420 may contain one or more geophysical sensor devices that can measure the parameters such as formation resistivity, formation radiation, formation density and formation porosity. Sensor devices can be attached to mechanisms in accordance with the preparation shown in figures 42 to 47 (see below). A portion of the casing (here, the middle casing portion 2404B) is placed around the portion of the BHA 2400 with the resistivity device, which preferably has one or more resistivity antennas used in conjunction with the resistivity device. The resistivity assembly group 2420 is not necessary in this invention and only when resistivity measurements are desired during or after drilling.

[000253] Below the resistivity mounting group 2420 in the BHA 2400 is the MWD/LWD mounting ring group 2424, which contains one or more MWD or LWD sensor 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 lead wire; gyroscopic telemetry electromagnetic device; gyroscopic telemetry acoustic device; gyroscopic telemetry mud pulse device; magnetic dipole including single shot and telemetry; casing with wire as shown and described in relation to the U.S. Application Serial Number 10/419,456 entitled “Wired Casing” which was filed on Apr. 21, 2003 and which is incorporated by reference in its entirety.; and fiber optic sensor devices. Any combination of sensors and/or telemetry can be used in this invention. As with the resistivity array sensor devices 2420, the MWD/LWD array sensor devices 2424 can be attached therein by the mechanism shown in Figures 4-472. The sensor device(s) inside the MWD/LWD assembly 2424 are used to measure the angle with respect to the vertical axis of the casing 2404 on the surface where the casing 2404 is derived. The angle can be measured in real time while the casing 2404 is being drilled at the surface and while the inspection tool remains in the MWD/LWD assembly assembly 2424, or alternatively the angle can be measured at intervals by temporarily stopping drilling to allow the inspection tool to be lowered into the MWD assembly assembly 2424 and measuring the direction of casing 2404. Measuring the angle at which casing 2404 is drilled or has been drilled allows the operator to adjust conditions such as the amount of drilling fluid flowing through the casing 2404 or the pressure on the casing 2404 from the surface to the lower casing 2404 inside the soil formation, to change the deflection angle of the casing 2404 inside the formation.

[000254] Because co-directional directional MWD and LWD sensors are magnetic, the casing 2404 around the MWD/LWD mounting assembly 2424 must typically be non-magnetic. However, because casing 2404 remains in the well during casing drilling, and because non-magnetic casing is more expensive than magnetic casing commonly used for casing drilling, it is desirable in some situations to drill with magnetic casing. To this end, a gyroscope can be used as the directional MWD/LWD sensor to eliminate the need to use non-magnetic casings around the MWD-LWD mounting assembly 2424. Magnetic casings can then be placed around the MWD/LWD mounting assembly 2424. it is desirable that the gyroscope sensor used in this invention is of the type Gyrocopedata Gyro-Guide GWD (gyroscope-while-drilling) tool, as shown and described in Gyrodata Services Catalog, 2003, page 31. Gyro-Guide is fully integrated into the control system that exists in the MWD tool string (here, the BHA 2400) which includes wireless telemetry for use in inspecting while drilling. Use Gyro-Guide at GWD so that the operator does not have to constantly stop the drilling process. Place inspection tool (eg, gyroscope) into casing 2404 with lead wire, take measurements. The inspection tool is then removed before drilling continues.

[000255] In the BHA 2400, there is a mud motor 2425 below the MWD/LWD assembly 2424. There is an expansion bit 2426 and a pilot drill bit 2428 which are connected below the mud motor. The pilot drill bit 2428 and the expansion drill bit 2426 can be replaced but a bi-center drill bit in one manufacture. The mud motor 2425 provides rotational load on the expansion bit 2426 and the pilot drill bit 2428 relative to the mud motor 2425 through a motor bearing pack 2429 when one wishes to rotate the pilot drill bit 2428 relative to the BHA 2400 and the casing 2404 and drill rotary in the formation. The mud motor 2425 used may be similar to the mud motor as shown and described in figures 1-12. Pilot bit 2428 and expansion bit 2426 drill casing 2404 into the formation. It is desirable that the pilot drill bit 2428 can sidecut so that it is possible for the casing 2404 to be turned at an angle in relation to the centerline of the wellbore after drilling next to the wellbore.

[000256] An optional stabilizer 2430 similar to the stabilizer 2422 may be placed around the outer diameter of the BHA 2400 at a location near the connection between the MWD/LWD assembly assembly 2424 and the mud motor 2425. It is desirable that the stabilizer 2430 be placed adjacent to an eccentric casing bevel pad 2435 (described below). In the same manner as the stabilizer 2422, the stabilizer 2430 is also positioned axially on the BHA 2400 relative to the casing 2404 by connecting the annulus between the BHA 2400 and the casing 2404. One more concentric stabilizer 2432 is positioned concentrically around the outer diameter of the mud motor 2425 near the lower end of casing 2404 to stabilize the lower end of BHA 2400 relative to casing 2404.

[000257] The main stress at the directional slope of the casing string 2404 (relative to the vertical axis of the casing string 2404 entering the formation from the surface) is found due to an eccentric casing bias pad 2435. The casing bias pad 2435 is positioned on only one side of the casing 2404 on the outside diameter of the casing 2404 to push the centerline of the casing 2404 to an angle relative to the wellbore centerline, thereby causing the casing 2404 to be off-center relative to the well hole. Casing bevel pad 2435 is located near the lower end of casing 2404. The directional bevel angle of 2404 is on the opposite side of casing 2404 relative to the side of casing 2404 where casing bevel pad 2435 is attached. For example, as shown in Figure 35, the eccentric bias pad 2435 is located on the right side of the casing 2404; therefore, the angular deviation of the casing 2404 stays to the left of the center line of the wellbore. In one production, the casing inclined pad 2435 can cover approx. 90-100 degree circumference, but any angle is possible with this invention. The height of the casing slope pad 2435, or the distance from the inside of the casing slope pad 2435 attached to the outer diameter of the casing 2404 to the outer side of the casing slope pad 2435 which is farthest from the casing 404 outer diameter, is determined before the assembly is inserted into the wellbore. The height of the casing slope pad 2435 determines, at least in part, the angle that the casing 2404 deviates from the center line of the wellbore. In an additional embodiment of this invention, the inclined pad 2435 can be an eccentric stabilizer instead.

[000258] With the eccentric casing pad 2435, the directional load during directional drilling of the wellbore is approximately perpendicular to the part of the casing pad 2435 that is perpendicular to the casing axis 2404. The load is transferred from the outer part of the casing pad 2435 to the casing 2404 so that the directional the load is primarily taken up by the casing 2404 instead of the BHA 2400, primarily because the BHA 2400 is located almost entirely within the casing 2404 rather than a large portion of the BHA 2400 protruding below the casing 2404. In the embodiment shown in Figure 35, the pilot drill bit 2428 , the expansion drill 2426 and a part of the mud motor 2425 the only parts of the BHA 2400 that protrude below the casing 2404. It is desirable that the part of the BHA 2400 that is open is to approx. 1.5 m to 3.0 m in length. Finally, the directional bias load is transferred from the wellbore to the casing pad 2435, the stabilizer 2432, through the motor bearing pack 2429, and then to the expansion bit 2426 and the pilot drill bit 2428.

[000259] In addition to locking the BHA 2400 to the casing 2404, the casing detent 2406 aligns the face of the MWD or LWD tool (not shown) contained within the BHA 2400 to the casing bevel pad 2435 so that the location of the casing bevel pad 2435 on the casing 2404 is, and as a result the angle at which the casing 2404 is drilled, easy to determine in relation to a reference point. The torque blades 2405 on the casing detent 2406 maintain the rotating position of the BHA 2400 relative to the casing 2404, thereby aligning the sensor relative to where the eccentric pad 2435 is located by preventing rotation of the BHA 2400 inside the casing 2404. Similarly, MWD- The /LWD tool is locked onto the MWD/LWD assembly assembly 2424 by the device and method shown and described with respect to Figures 42 through 47 so that the MWD/LWD tool does not rotate relative to the casing stopper 2406 main body, thus retaining the rotating the position of the MWD/LWD tool relative to the casing stopper 2406 body so that the position of the eccentric camber 2435 can be easily determined. In this way, the operator can keep track of the direction in which the casing 2404 is drilled so that the wellbore continues to be drilled in the same direction as desired.

[000260] Figure 36 shows casing 2504 with a BHA 2500 releasable detent attached to the inside diameter thereof with a casing detent 2506. As stated above in connection with Figure 35, the casing detent 2506 can be replaced by any means of attaching the casing 2504 to BHA 2500. The components of the casing including the casing parts 2504A, 2504B, 2504C, the profile collar 2511 including the profiles 2513, 2515 and the casing coupling 2516 are substantially similar to the casing parts 2404A, 2404B, 2404C, the profile collar 2411, the profiles 2413, 2416, and the casing coupling 2416 and described. in the context of Figure 35.1 addition, most of the BHA components include the threads 2519, the packer element 2517 and the cups 2518, the axial and torque blades 2507 and 2505, the resistivity assembly assembly 2520, the MWD/LWD assembly assembly 2524, the expansion bit 2526, the pilot drill bit 2528 and the stabilizers 2522, 2503 , and 2532 mostly like the threads 2419, the packer elements 2417, the cups 2418, axial ades and torque blades 2407 and 2405, resistivity assembly assembly 2420, MWD/LWD assembly assembly 2424, expansion drill bit 2426, pilot drill bit 2428, and stabilizers 2422, 2430, and 2432, as shown and described in conjunction with Figure 35. Therefore, the above description applies to these components to the same extent the representation shown in figure 36.

[000261] The casing stopper 2506 in Figure 6 is largely similar to the casing stopper 2406 in Figure 35, therefore most of the above description of the casing stopper 2406 applies to the same extent to the manufacture shown in Figure 36. The main difference between the casing stopper 2506 and the casing stopper 2406 is that the casing stopper 2506 in Figure 36 does not have an alignment detent to keep track of the location of the casing bias pad 2535 because the casing bias pad 2535 in Figure 36 functions as a concentric stabilizer (see description below).

[000262] Instead of the mud motor 2425 in Figure 35, a flex housing mud motor 2550 is coupled to the lower end of the MWD/LWD assembly 2524. The flex housing mud motor 2550 includes a flex motor that engages the rod rack 2555 which is bent at an angle such that the casing 2504 is inclined while drilling at an angle to the centerline of the wellbore. The motor rack connecting the rod rack 2550 is at an angle to the rest of the BHA 2500 and at the desired angle and direction to bevel the casing 2504.

[000263] Another difference between the system in Figure 35 and the system in Figure 36 is that instead of the eccentric casing pad 2435 in Figure 35, the casing pad 2535 in Figure 36 is circumferential and can be called a stabilizer. Instead of using an eccentric camber that adjusts the angle of the casing 2504, the flex motor connecting the rod rack 2555 provides for this adjustment of the angle.

[000264] In the same manner as in the embodiment in Figure 35, the embodiment shown in Figure 36 shows the main part of the BHA 2500 located inside the casing 2504. The only parts of the BHA 2500 that are located below the casing 2504 are a part of the bending motor that connects the rod rack 2555, motor bearing pack 2529, the expansion drill 2526 and the pilot drill bit 2528. Again, it is desirable that the part of the BHA 2500 that is below the casing 2504 is only approx. 1.5 m to 3.0 m.

[000265] Using the embodiment of Figure 36, the directional biasing load comes from the motor buoy pushing against the side of the wellbore and providing a resultant load on the opposite side of the pilot drill bit 2528 and the expansion bit 2526. But the directional biasing load is transferred by the casing 2504 instead of the BHA 2500 which in the representation in Figure 35, so that the directional bias load is transferred from the wellbore to the casing pad 2535, and then to the stabilizer 2532, through motor bearing pack 2529 and then to the expansion drill bit 526 and the pilot drill bit 2528.

[000266] As with the preparation shown in Figure 35, the height of the casing slope pad 2535 is determined before the well assembly is lowered. But in the representation in Figure 36, the bending angle of the mud motor is adjustable from above and/or down in the well to be able to adjust the angle of the casing 2504 which is used during drilling. In the production in both figures 35 and 36, the height and/or diameter of the casing inclined pad 2435, 2535 (or eccentric stabilizer) is also adjustable above the wellbore and/or in the well.

[000267] In the embodiment of Figures 35 and 36, the non-magnetic casing member 2404C or 2504C may be made of any non-magnetic material compatible with MWD sensors. Other non-magnetic casing alternatives are also contemplated for use with this invention. The non-magnetic casing can be a composite or metal. Resistivity measurements from the resistivity assembly group 2420, 2520 may require repacking the sensor antennas and/or having a special resistivity casing joint.

[000268] In the above embodiment which is shown and described in connection with Figures 35 and 36, instead of the expansion drill 2426, 2526 and pilot drill bit 2428, 2528, an expandable drill bit (not shown) can be used which can be expanded to drill the wellbore and can contracts to a smaller outer diameter as it withdraws the BHA 2400, 2500 from the casing 2404, 2504. An example of an expandable drill bit that can be used with this invention is described in U.S. Pat. Patent Application Publication No. US2003/1 1 1 267 or U.S. Patent Application Publication No. 2003/183424. Both of these are incorporated by reference in their entirety.

[000269] The BHA 2400, 2500 components, including the detent 2406, 2506, the MWD/LWD assembly assembly 2424, 2524, and the resistivity assembly assembly 2520, may be assembled in a different order than shown in Figures 35 and 36.1 In addition, the stabilizers 2422, 2522, 2430 , 2530 and 2432, 2532 are placed at other longitudinal locations on the outside diameter of BHA 2400, 2500.

[000270] The use of the fabrication shown in Figures 35 and 36 includes assembly of the BHA 2400, 2500 and casing 2404, 2504. The BHA 2400, 2500 and casing 2404, 2504 assembly is lowered into the formation and the assembly is drilled at an angle to the vertical wellbore drilled into the formation. If desired, the mud motor can rotate the pilot bit 2428, 2528 while drilling is in progress at an angle. When the assembly is drilled to the desired depth for the casing 2404, 2504 to be down in the wellbore, the BHA 2400, 2500 is disconnected from the casing 2404, 2504. The casing 2404, 2504 is lowered over the BHA 2400, 2500, and the BHA 2400, 2500 is then pulled out of the wellbore using a tubular main part such as a drill pipe or a wire. The casing 2404, 2504 can be cemented into the wellbore. More casing (not shown) can then be drilled through the casing 2404, 2504 into the formation and can be extended into the casing 2404, 2504. This process can be repeated if desired.

[000271] Figure 37 shows another representation of a directional drilling assembly. Specifically, the BHA 2700 is equipped with an articulated stand 2760 that provides the directional slope for drilling. As shown, the BHA 2700 is releasably attached to the inside diameter of the casing 2704 using a casing stopper 2706. As expressed above in the context of Figures 35 and 36, the casing stopper 2706 can be replaced by any means of attaching the casing 2704 to the BHA 2700. .The components of the casing including the casing parts 2704A, 2704B, 2704C, the profile collar 2711 including the profiles 2713, 2717 and the casing coupling 2716 are generally similar to the casing parts 2404A, 2404B, 2404C, the profile collar 2411, the profiles 2413, 2415 and the casing coupling shown in Figure 42 and shown in connection with Figure 46. 35. Additionally, most of the BHA components include the threads 2719, the packer elements 2717 and cups 2718, the axial and torque blades 2707 and 2705, the resistivity assembly assembly 2720; MWD/LWD Assembly Group 2724, Expansion Drill 2726, Pilot Drill Bit 2728 and Stabilizers 2722, 2730 and 2732 substantially similar to Threads 2419, Packer Elements 2417, Cups 2418, Axial Blades and Torque Blades 2407 and 2405, Resistivity Assembly Group 2420, MWD/LWD Assembly Group 2424 the expansion drill 2426, the pilot drill bit 2428, and the stabilizers 2422, 2430 and 2432, as shown and described in connection with figure 35. Therefore, the above description of these components also applies to the manufacture shown in figure 37.

[000272] Instead of a bending motor 2550 as shown in Figure 36, a drill motor 2750 is used which is equipped with an articulated stand 2760 and provides a torque to rotate the pilot drill bit 2728 and the expansion bit 2726 as shown in Figure 37. The articulated stand 2760 can be rotated to form an angle between the drill motor 2750 and motor bearing pack 2729. This means that the pilot drill bit 2728 drills at an angle in relation to the center line of the wellbore. In comparison to the bending motor 2550, the articulated stand 2760 allows the drilling motor 2750 to pass through the casing 2404 in a generally concentric manner. In this context, a large drilling motor can be installed at the bottom of the hole assembly. This gives the pilot drill bit 2728 more power.

[000273] Figures 38A-B show an example of an articulated stand 2760 according to the various aspects of this invention. The articulated stand 2760 has a first link 2761 which can be assembled with a second link 2762 as shown in figure 38A. In one embodiment, the first link 2761 is connected to the drill motor 2750 and the second link 2762 is connected to the motor bearing pack 2729. As shown, the first and second links 2761, 2762 are connected using male and female couplings 2765. More specifically, each of the male coupling links 2763 on the first link 2761 connects to the respective female coupling link 2764 on the second link 2762. A pin 2766 can be inserted through the male and female coupling 2765 to ensure that the links 2761, 2762 are fixed together. In addition, a sleeve 2767 may be placed around the pins 2766 to prevent the pin 2766 from separating from the connectors 2765. Alternatively, the sleeve may be attached to the joint stand 2760 using a pin or screw 2769. Alternatively, the first joint 2761 may include one or more stabilizers 2768. which is applied to it.

[000274] Figure 38B is another cross-section of the articulated stand 2760, rotated 90 degrees relative to Figure 38A. As shown, the second link 2762 is bent from the centerline of the first link 2761. This is because the pin coupling 2765 acts as a hinge that allows relative rotation between the first and second links 2761, 2762. In this connection, the motor bearing pack 2729 and the pilot bit 2728 can be bent in relation to the center line of the drill motor 2750. It is desirable that the articulated stand 2760 be adjusted so that the motor bearing pack 2729 can be bent up to 7 degrees from the center line; and even more desirable up to 5 degrees; and most desirable up to 3 degrees.

[000275] Figures 39 to 41 show another embodiment with directional drilling assembly. In Figure 39, a BHA 2900 is transported through a casing 2904. The BHA 2900 includes a casing stopper 2906, MWD/LWD tool 2924, an expandable stabilizer 2902, and a flexible collar 2910. The drill motor 2950 is equipped with an articulated stand 2960 and a motor bearing pack 2929. An extendable drill bit 2928 is used to extend the wellbore. It must be noted that the description given herein of the components also applies to the manufacture shown in Figures 39 and 41. The MWD/LWD tool 2924 can e.g. include sensors to monitor conditions in the wellbore such as pressure and temperature as previously described. On entry, the expandable stabilizer 2902 and the expandable drill bit 2928 have collapsed. In addition, the articulated stand 2960 is approximately vertical. Compared to a BHA with a bending motor, the articulated stand 2960 provides more clearance between the drilling motor 2950 and the casing 2904.1 in this context, a larger drilling motor can be used to obtain a greater torque in the well.

[000276] In Figure 40, BHA 2900 has reached the bottom of the wellbore, but the drilling process has not begun. As shown, the casing lock 2906 has been released to connect the BHA 2900 to the casing 2904. It can be seen that the joint rack 2960 and the BHA 2900 are still substantially vertical.

[000277] In Figure 41, the drilling process has begun. The articulated stand 2960 is loosened by applying a load to the stand 2960. Because the expandable drill bit 2928 is in contact with the bottom of the wellbore, the stand 2960 experiences a load from above and below which causes the stand 2960 to bend. In this way, the expandable drill bit 2928 can be deflected relative to the center line. In addition, the expandable stabilizer 2902 can be used to help control the direction as discussed above. For example, the expandable stabilizer 2902 can be partially extended and partially retracted as shown. It can also be seen that the expandable drill bit 2928 has been extended to form a larger diameter hole to accommodate the casing 2904.

[000278] Referring first to Figure 42 where a cross section of the wellbore 10A where drilling is carried out is shown. The wellbore 10A is a directional drilled wellbore with an access part 12A which goes from the surface 14A to the inclined part 16A down into the formation 18A where it is likely that hydrocarbons will be found. Despite the fact that the wellbore 10A is shown with a normal knee profile, it may have other profiles, such as slanting downward into the earth in relation to vertical.

[000279] In order to drill in the surface and thus create the well hole 10A, a drill string 20A is required which consists of several lengths of pipe 22A (one such is shown in Figure 43) and well equipment, such as e.g. a buoy assembly group 30A, drill bit 32A and/or float tool 34A to drill the well. These hang from a drilling platform 24A on a tower 26A. The derrick 26A has equipment used (not shown) to set the rotary position of the drill string 20A, to control the depth position of the drill string 20A, and to supply fluids such as drilling mud, water, cement, or other fluids used in drilling the wellbore 10A or down through the hollow center portion 28A (shown in Figure 43) of the drill string 20A to drive the drill motor which causes the drill bit 32A to rotate.

[000280] In Figure 43, there is a float assembly group 34A of this invention which, in this embodiment, is completely inside a part of the pipe 20A in the buoy assembly group part and thus is placed inside the drill string 20A at the time drill string 20A and placed in the surface. The float assembly group 34A usually includes an annular main part 36A which is configured with a central opening 38A through which the well peripheries such as the guide shoe with beveled edge 52A and the valve 42A can be placed. It is desirable that the main part 36A is configured from a drillable material such as e.g. cement used to secure the annulus between the wellbore and the drill string 20A, where the drill string 20A is used as a liner, or out of plastic, cast iron, aluminum, or similar materials that are easy to drill into so that the main body and the accompanying beveled guide shoe 52A and the valve 42A can be easily removed from the casing by drilling them out of position in the drill string 20A. The center opening 38A includes an upper guide portion 44A which in this embodiment is configured as an undivided frustoconical surface with a taper from a counter-rotating profile 31A and located on the upper surface of the float assembly main portion 34A leading to the land bore 46A and terminating in the enlarged valve receiving bore 48A . The land drill 46A is generally a right cylindrical drill which aligns with the sleeve 50A and which has a shoe 52A which is used to receive the inspection tool 60A (shown positioned above the float assembly assembly 34A in Figure 43) which is aligned within the float assembly assembly 34A. As shown in Figure 43, the shoe 52A is usually a tubular joint, the upper end of which is securely fixed in the inside diameter of the sleeve 50A at the lower end of it in the land drill 40A. The upper surface of the shoe 52A has a guide shoe profile with a beveled edge 54A, i.e. the top annular surface 56A of the shoe 52A facing upwards in the direction of drilling is configured as a straight cut across the tubular profile of the shoe 52A at an angle to the centerline of the shoe 52A as that the circumference of the upper end point of the shoe 52A at the guide shoe profile with bevelled edge 54A is an ellipse. In addition, the shoe 52A has a slot 58A which goes down into the well from the guide shoe profile with a slanted edge 54A in the wall of the shoe 52A. It is understood that the guide shoe profile with bevelled edge 54A may include other geometric shapes in addition to an ellipse.

[000281] Reference is still made to Figure 43. The valve main part 62A is received down in the well from the shoe 52A in the valve receiving bore 48A. Typically, the valve body 62A includes a rack 64 having a through-bore 66A therethrough extending from the lowermost extension of the shoe 52A to a valve assembly 68A. It is desirable that the rack 64A is cast into, threaded into or otherwise permanently attached to the main part 34A before the float assembly group 34A is placed inside the drill string 20A. The valve assembly 68A is shown in this illustration as a "plate" valve, i.e. a valve with a cover plate 70A which is connected to a spring-loaded hinge 72A on the stand 64A so that the cover plate 70A is in a closed position over the opening of the drill 66A on the underside of the stand 64A and thus the drill is sealed so that liquid does not enter somewhere in the well and into the drill 66A and thus into the cavity 28A on the drill string 20A. However, when fluid is directed into the cavity 28A of the drill string 20A, such fluid can pass through the hollow portion of the sleeve 50A and the beveled guide shoe 52A, and thus through the through-bore 66A to provide sufficient pressure on the valve so that the cover plate 70A opens over hinge 72A. Thus, such liquids can pass through it and further down a part of the drill string 20A. The liquid can go inside the wellbore through the mud passage in the drill bit. In another embodiment, the fluid may pass through the passages in the mud driven drill motor (not shown) before reaching the drill bit. The configuration of the float assembly assembly 34A shown in Figure 43 generally places the sleeve 50A co-linear with the center of the drill string 20A and an inspection tool is placed therein. This will, as described in more detail later, place the inspection tool in the middle of the drill string 20A. However, there are inspection tools where it is useful to place the inspection tool to one side of the drill string 20A, therefore the drill bit 46A on the float assembly group 34A can be pushed to one side or the other (ie, not co-linear with the centerline of the drill string 20A) so that the sleeve 50 will in the same way be displaced in relation to the center line of the drill string 20A.

[000282] Reference is still made to Figure 43. The inspection tool 60A is shown inside the drill string 20A where it hangs on a wireline 102A above (or next to) the float assembly group 34A. The inspection tool 60A generally includes a hollow, generally cylindrical main portion 104A with an outer cylindrical portion 106A having an inside diameter substantially equal to the diameter of the shoe 52A and an outside diameter slightly smaller than the inside diameter of the sleeve 50A in which the shoe 52A is placed. , an upper cover part 108A to which the lead wire goes from the tool 60A and a lower end 110A which is open. The lower end 11 OA is also configured with a matching bevel guide shoe profile 100A (shown in Figure 43A), cut at the same angle as the shoe 52A, to provide a matching elliptical surface as on the bevel guide shoe profile 54A of the shoe 52A. Figure 43A shows the inspection tool 60A from the side with a mating profile 100A that mates with the guide shoe profile with beveled edge 54A on the shoe 52A.

[000283] To extract the inspection tool 60A from the well where the tool 60A is separated from the lead wire 102A, the cover part 108A may include a fishing neck 112A which is used to extract the inspection tool 60A with a fishing tool (not shown). In another embodiment, the tool 60A can be intentionally separated from the lead wire 102A and remain in place. In another embodiment, the tool 60A may be pre-assembled with the shoe 52A to be later pulled out with lead wire or pipe. The body 104A also includes multiple flow passages 116A passing through it that allow fluids to flow between the hollow portion 28A of the drill string 20A and the interior volume 118A of the body 104A. There are several stabilizers 120A on the exterior surface of the main portion 104A that help center the inspection tool 100A in the drill string 20A as it is lowered from the surface through the hollow portion 28A.

[000284] There is a diagnostic device 108A inside the inspection tool 60A which is connected to the lead wire 102A and which passes through the upper cover part 108A. In the embodiment shown, this diagnostic device 114A is a geosensor and transmitter combination which, in conjunction with a computer and software, can determine the direction of the wellbore 10A in the earth, which is necessary to ensure that the wellbore 10A is drilled in the desired direction that the rotating position of the inspection tool 60A is known.

[000285] Figure 44 shows the location of the inspection tool 60A in the shoe 52A. The inspection tool 60A is lowered into the hollow portion 28A of the drill string 20A of the lead wire 102A so that the lower end 110A thereof is located inside the land drill 46A of the float tool 34A. Where the inspection tool 60A is not axially aligned with the land drill 46A, i.e., offset to one side of the drill string 20A, its lower end will engage the tapered surface 44A of the alignment drill 46A and be guided toward the opening of the sleeve 50A. As the inspection tool 60A is lowered further down, the lower end will enter the sleeve 50A and the mating bevel guide shoe 100A on the lower end 110A of the inspection tool 60A will contact the bevel guide shoe profile 54A on the shoe 52A. Where the rotary alignment of the two profiles is such that the surfaces of their elliptical surfaces are not parallel, lowering the inspection tool 60A further down will cause the end 110A of the inspection tool 60A to slide on top of the beveled guide shoe profile 54A of the shoe 52A. At the same time, this will cause the inspection tool 60A to rotate until the inspection tool 60A has reached all the way into the profile 54A so that the flat elliptical surfaces on each of the profiles 54A, 100A have parallel contact.

[000286] In the desirable embodiment thereof, the drill shoe includes a cutting device which may be a traditional rock drill bit, a drill motor, or the like, preferably configured to be pierced by a subsequent, smaller drill shoe which is passed down the casing. Alternatively, the drill shoe may include a jet portion with multiple fluid jets extending from a center drill bit (not shown) to the outside thereof at a known peripheral position. It is desirable, as is known in the art, that one can choose the liquid jets when these are controlled to make it possible to jet into the formation for the removal of formation substances and thus form bending in the direction of the wellbore. Thus, the drill string (or drill motor) can be rotated to drill forward or that the jets can be fed in by rotary setting and one can select these to perform directional drilling. It is desirable that the drill bit has several mud passages through which drilling fluids can pass to lubricate or cool the cutting surface and make it possible to remove cuttings from the wellbore while the drilling fluid is recycled on the earth's surface.

[000287] The location or rotational alignment of the guide shoe profile

with bevel 54A which is known before the inspection tool 60A is placed in it, makes it possible to perform several functions in the well with a high degree of accuracy. In one case, the inspection tool 60A may be a gyroscope that is adapted to obtain location information in a wellbore. The information about the location is communicated to the surface via the lead wire 120A. Surface components or control devices can receive information about the location of the gyroscope and the rotating position of the casing, including the buoy assembly group. Alternately, the position of the casing or buoy assembly can be changed by rotating the casing at the surface to obtain the desired position or position. Afterwards, the gyroscope can be removed via the lead wire 120A, or if necessary via the fishing tool. After the inspection is done, it can be drilled or beamed through selected ports in the beam part of the drill shoe to create a new or desired direction on the wellbore. The new direction of the wellbore can be determined and confirmed by placing the gyroscope on the beveled guide shoe profile 54A. Any other changes in the direction that is determined can be carried out as needed in accordance with the methods described above.

[000288] Alternatively, an MWD tool or LWD tool 600A with an inspection tool 660A can be used to determine and control the drill shoe (found below 620A) as drilling progresses, as shown in Figure 47. Many types of sensors can are used, including magnetic sensors, gravity sensors, gyroscope sensors and any combination of these. In addition, many types of telemetry including mud pulse, electromagnetic, acoustic, wireline, fiber optic, casing with wire and any combination of these. Any combination of sensors and telemetry can be used. The advantage of using the fluid powered or continuous MWD/LWD tool 600A is that drilling can continue with the inspection tool 660A positioned on the drill bit 646A. Drilling can continue using a drill motor 625A where the casing 605A does not need to be rotated because the drill shoe 620A is then driven by the mud flow, or a traditional rock bit is used and the casing 605A can be turned to provide formation bit movement and cutting force. The MWD/LWD tool 600A can be equipped with a mud pulse telemetry component 61 OA to send information about e.g. inclination and azimuth of the wellbore back to the surface. In one case, mud pulse telemetry 61 OA includes manipulating fluid flow through holes 616A by varying the total flow area of holes 616A so that pressure pulses can be sensed at the surface. In this case, mud pulse telemetry 61 OA is a way to convey information from the well to the surface. In this way, the direction of the wellbore can be checked while drilling is in progress or when drilling is not in progress. It must also be noted that information can therefore also be sent back to the surface using methods that are commonly known in the art. An example is electromagnetic communication.

[000289] Figures 42 to 44 refer to the float assembly group 34A and the inspection tool 60A which together make it possible to perform drilling and inspection simultaneously, in addition to being able to perform other useful tasks down the well. Among these is safe placement of the inspection tool 60A in the float assembly group 34A while drilling mud, water, cement or when other fluids are flowing through. This applies to cases where fluids flow from the surface down into the hollow part 28A of the drill string 20A. Such fluid, upon reaching the inspection tool, presses on the inspection tool and tends to hold it to the shoe 52A, and such fluids also flow through the flow passages 116A to the cavity 118A of the inspection tool. Such fluids flow through the hollow bore in the shoe 52A and the bore 66A in the valve body 64A so that it presses on and opens or holds open the valve cover plate 70A. In this way, the fluid continues to flow down through the rest of the drill string 20A to places such as, for example. the drill or the mud motor and the mud passages in the drill bit (not shown) and then on the annulus between the drill string 20A and the wellbore 10A. If the fluid flow down through the drill string 20A is interrupted or stopped below the valve 68A and is greater than the mud pressure at the valve 68A, the fluid in the annulus will flow back up into the drill string 20A if it is not blocked. Such backflow will dislodge the inspection tool from the shoe 52A and may damage the inspection tool 60A. However, because the cover plate 70A of the valve body 42A is spring-loaded by the hinge 72A to be tilted in a closed direction, where the pressure across the valve approaches the applied back pressure, the cover plate 70A will close over the bore 66A. If the back pressure is increased more due to the fluid in the annulus 10A, it will only increase the pressure on the closure device and thus seal the drill bit 66A and prevent more backflow or more flow of fluids up through the drill string 20A. Although the valve 68A has been described as a poppet valve, it may be replaced by other valves such as check valves, seat valves, automatic filling valves or differential valves, the use and design of which are well known to those skilled in the art, without departing from the scope of the invention.

[000290] Figures 45 and 46 show an alternative configuration of the inspection tool. In this embodiment, the design of the inspection tool 200A is similar to the inspection tool 60A, except that the bevel profile guide shoe of the inspection tool 60A is replaced so that the open lower end 202A of the inspection tool 200A is generally a right circular cylinder and there is an alignment pin 204A on the outer surface of the tool 200A. When this tool is lowered into the float assembly assembly 34A from the position in Figure 45 until it has come into place in the inspection tool 200A as shown in Figure 46, the pin 204A will attach to the beveled guide shoe profile 54A of the shoe 52A and slide along it. In that way, the inspection tool 200A is rotated as shown by the tool 200A being rotated 90 degrees between Figure 45 and Figure 46. As the tool 200A goes further into the shoe 52A, the pin 204A will align with the slot 58A. As the tool 200A is lowered further, the pin 204A will move down to the bottom of the slot 58A. At that point, the tool 200A will be firmly in place and aligned with the shoe 52A. The inspection tool 204A is smaller in diameter than the inspection tool 60A because it must slide inside the shoe 52A while the inspection tool 60 rests on the upper surface of the shoe 52A. The inspection tool 200A is in all other respects similar to the inspection tool 60A and the use of the tool 200A in connection with mud flow through it is similar to that of the inspection tool 60A.

[000291] As with the inspection tool 60A, the location or rotational alignment of the inspection tool 200A is known as to the location of the bend assembly, the drill shoe, or the beam member because the location of the slot 58A is known as to these parts of the drill string when they are assembled before being placed. in the well hole. Therefore, the inspection tool 200A can consist of a gyroscope and signals from it tell the direction in which the wellbore is moving and the alignment or location of the drill shoe components can be sent to the surface on the wireline 120A to be able to adjust the drill shoe components if necessary, in the same way as was done with the inspection tool 60A . An MWD/LWD tool may also be placed in the float assembly assembly 34A and use the alignment provided by the slot 58A to continue drilling and steering using the MWD/LWD. Once the MWD/LWD tool is in place on the float assembly assembly 34A, the MWD/LWD tool can communicate the inspection information to the surface via mud pulse telemetry. That way, you don't have to remove the inspection tool to drill further.

[000292] The float assembly assembly 34A of this invention has several useful functions when in a drill string 20A. First, the shoe's 52A position in relation to the drill bit is noted before it is placed in the float assembly group 34A down in the wellbore. This makes it possible to use data obtained from or calculated by the inspection tool to follow the surface being drilled. In addition, the shoe 52A makes it possible to activate the rotation alignment of the inspection tool 60A, 200A down in the well, when it sits in the float assembly group 34A, which also makes it possible to retrieve important data and know about the advancement of the drill bit. In addition, the use of a setting element in combination with flow through the inspection tool 60A, 200A enables drilling mud or other fluid to flow down into the drill string 20A to ensure that the inspection tool 60A, 200A stays in place and thus in the correct position while the inspection is in progress. Likewise, this allows inspection to take place while fluids are flowing through the system and thus while drilling is in progress.

[000293] In each case, the float assembly assembly components 34A must be removed or otherwise arranged so that it does not impede the production of fluid from the well after the inspection is completed and one needs to restart well production. Because the inspection tool 60A, 200A only sits in the float assembly group 34A, it can be easily removed from the float assembly group 34A such as by extending the fishing tool (not shown) and attaching the fishing neck 112A to pull the inspection tool out of the drill string 20A, or if the lead wire 102A is sufficiently strong, the inspection tool can be pulled up with the lead 102A. Other ways to do so are for the inspection tool 60A, 200A to be attached to the float assembly assembly 34A with a ring assembly, secured in place with shear screws, or other methods commonly known to those skilled in the art to extract the inspection tool with relative ease.

[000294] Once the inspection tool is removed, the float assembly assembly 34A is used to cement the casing 22A, which consists of the drill string 30A in place in the wellbore, to line the wellbore. In this case, cement is discharged down the inside 28A of the casing 20A and through the float assembly group 34A (as floating drilling fluid) and then out through the mud passages in the drill shoe or other cementing passages designed for it and into the annular space between the drill string 20A and the wellbore 10A and 16A. It may be necessary to harden the cement in place without anything inside it up through the drill string before it hardens. Therefore, when cementing fluid no longer flows down through the drill string and another lighter fluid is discharged into the drill string directly after the cement, the pressure in the drill string will be less than in the annulus between the drill string 20A and the wellbore 10A and 16A and the valve assembly 68A will close over the opening on the drill bit 66A on the underside of the stand 64A to seal the drill bit so that cement does not enter the cavity 28A of the drill string 20A. Another way is to place one or more isolation assembly groups (not shown) above or below the float shoe 34A to prevent cement from leaking into the cavity 28A if cement leaks past the valve assembly 68A.

[000295] After the cement has hardened, the float assembly assembly 34A is removed. The usual way is to insert a drill, grinder or cutter into the hollow portion 28A of the drill string 20A from the surface and physically cut or drill through the shoe, stand and valve assembly. It will be easy to drill, grind or cut through the cement or the plastic-based components of the float assembly group, in addition to any metal part, into small pieces that can be picked up, partly by coming to the surface with the drilling mud. In addition, there are advantages in that as many of the components as are practical, such as e.g. the valve body 48A, etc. is made of a material that is easy to grind or drill through, but has enough strength to retain its shape under pressure. After the float assembly assembly is removed, production tubing or other production elements can be easily placed through the drill string 20A and past the location where the float assembly assembly 34A was located. In cases where the wellbore has not yet reached its final length, an additional casing with drill bit cemented in place and connected to a drill motor to drill through the float assembly assembly 34A and a drill motor at the bottom of the shoe to drill down into the earth can be used .

[000296] Despite the fact that the invention describes a situation where the drill string 20A is to be used on site as casing, the invention applies to situations where a well is lined separately with a pipe. In such a construction, a part of the casing may have a float assembly group 34A with a fixed longitudinal and oblique alignment, and the distance from the float assembly group 34A to other places of interest such as e.g. the end of the lowest casing in the row is noted. In this way, the float assembly group 34A can be used to be able to align and place the inspection tool in the casing, even if drilling cannot take place at the same time.

[000297] Despite the fact that the float assembly group 34A has been described in the context of receiving and placing inspection tools, the float assembly group 34A can be modified so that it has several functions such as a locking collar or other device in which can be used to attach a locking system such as f .ex. a float collar or cementing tool. The float assembly assembly can also be configured to include a follower tool so that a blocking link, such as a ball (not shown) can be positioned so as to block 66A and thus cement can be passed through the follower portion thereof (not shown).

[000298] Another alternative is shown in Figures 48 through 52. Here, the present invention has an inspection tool assembly 900 that can be used while determining direction when drilling the casing. Figure 48 shows a casing 910 which has a drill bit 915 and a cementing valve 920 located in the lower part of the casing. In one embodiment, a portion of casing 910 may be made of a non-magnetic material. The drill bit 915 can have one or more fluid deflectors (drill bit nozzles) 925 where the angle is such that the desired trajectory is achieved. The casing 910 may also have a receiving connection 930 which connects with the inspection tool assembly 900. It is desirable that the receiving connection 930 is in line with or in engagement with the fluid deflectors (bit nozzles) 925 to enable placement of the inspection tool assembly 900.

[000299] The inspection tool assembly 900 may include inspection tools such as. MWD tool 935 and a gyroscope 936. In one embodiment, the inspection tool 935 is located in the body 940 of the inspection tool assembly 900 using one or more centralizers 942. A mud pulse device 945 may be used to transmit information from the inspection tool 935, 936 to the surface . The main part 940 has an extraction lock 950 located at one side and an adjustment key 955 located at the other end. The alignment key 955 is arranged to secure the receiving connection 930 in a manner that aligns the inspection tool assembly 900 with the fluid deflectors (bit nozzles) 925. One or more seals 908 may be used to prevent fluid leakage between the inspection tool assembly 900 and the casing 910. Additionally, spring collar centralizers 960 may be placed on the outer portion of the main body 940 to center the inspection tool assembly 900 in the casing 910.

[000300] Many types of inspection tools are activated by fluid flow. In such cases, the inspection tool assembly 900 includes an inlet channel 965 that allows fluid flow into the body 940 to actuate the MWD tool 935 and the gyroscope 936. However, many types of inspection tools are used within a fluid flow range that is often lower than that required in other operations, such as e.g. drilling. Therefore, the inspection tool must be withdrawn before the subsequent higher flow rate is initiated. The repeated extraction and placement of the inspection tool takes a lot of time and is expensive. Because of this, in several of the methods of the present invention, the inspection tool assembly 900 also includes a bypass valve 970 that allows subsequent operation to be performed at a higher flow rate without extracting the inspection tool assembly 900.

[000301] In one embodiment, the transfer valve 970 is located at the portion of the body 940 that is below the inspection tool 935, 936. The transfer valve 970 is initially held closed and in an inclined position by an inclined joint 975, as shown in Figure 48. An example of this is an inclined joint 975 with spring. When the transfer valve 970 is closed, the fluid in the casing 910 can only flow into the body 940 of the inspection tool assembly 900 through the inlet channel 965 as shown in Figure 51. It should be noted that there are other types of bypass devices that a person of ordinary skill in the art can consider within the methods which is used in the present invention, including diversion with a fixed outlet opening.

[000302] The bypass valve 970 can be opened if the flow rate is higher. More specifically, the bypass valve 970 opens when the flow rate in the casing 910 is greater than the directional load of the inclined joint 975. Once opened, some of the liquid in the casing 910 can be passed through the diverter valve 970 instead of the inlet channel 965 as shown in Figure 52. In this way, a higher flow rate can be supplied to perform subsequent operation at a higher flow rate.

[000303] During operation, the inspection tool assembly 900 is mounted inside the casing 910 and is lowered into the wellbore together with the casing 910. More specifically, the alignment key 955 is located in the receiving connection 930 to align the inspection tool assembly 900 with the fluid deflectors 925 as shown in Figure 49. A lower fluid flow rate is supplied to use the inspection tool 935, 936. The lower flow rate is not high enough to overcome the spring 975 on valve 970, but is high enough to open the cementing valve 920 as shown in Figures 49 and 51. It should also be noted that lower flow rate may be sufficient to use the bit 915 at a lower speed. Information collected by the inspection tool 935, 936 can be transmitted to the surface of the mud pulse device 945.

[000304] Transfer valve 970 opens when the directional load of the spring is greater than a higher flow rate. After the transfer valve 970 is opened, the fluid flow through the inspection tool assembly 900 can take place through the inlet channel 965 and the transfer valve 970 as shown in Figures 50 and 52. The higher flow rate can drive the drill bit 915 at a higher speed and provide greater fluid flow through the fluid deflectors (the bit nozzles). 925 and thus ensure more effective directional control. To collect inspection information, the fluid flow can be reduced to close the transfer valve 970 and allow the inspection tool 935, 936 to be used. Information collected by the inspection tool 935, 936 can be transmitted to the surface via mud pulse telemetry where a mud pulse device 945 is used. This inspection process and drilling can be repeated as desired. In this context, the inspection tool 935, 936 does not need to be pulled out and lowered into the well as the drilling progresses. This saves time and money during operation. After the drilling is complete, the inspection tool assembly 900 can be withdrawn in any manner by a person of ordinary skill in the art. It is desirable that the inspection tool assembly 900 is pulled out by locking the lead wire to the pull-out lock 950. In that way, the inspection tool assembly 900 can be used again at the next drilling.

[000305] All electromechanical devices, which are mentioned above, such as e.g. drilling tools, directional tools, sensor packages, cementing equipment, and the like can be controlled or activated by string rotation, mud pump circulation, electrical wireline signals, wireline signals on casing, or a combination thereof. Control and/or actuation using string rotation may include the use of multiple start/stop cycles and/or different revolutions per minute. Control and/or activation using mud pump circulation may include the use of multiple start/stops of the flow rate and/or varying the flow rate.

[000306] In one embodiment, the present invention provides a method of controlling the path of the lined wellbore with a drilling assembly consisting of a wellbore with lined pipe and a soil removal joint. A directional inclined drilling assembly is used at the same time as an earth removal joint. The lined pipe is sunk into the ground and the lined pipe in the wellbore, which was made by oblique drilling and sinking, remains in the wellbore. In one method, the directional oblique drilling consists of forcing fluid through a non-axially symmetric outlet opening in the drill assembly. In one embodiment, the non-axisymmetric outlet port is located on the ground removal joint. Another method consists of directional inclined drilling which presses the drill assembly against a non-axial pad device contained within it. In one embodiment, the non-axisymmetric pad devices are located on the wellbore casing.

[000307] In one embodiment, the present invention provides a method of controlling the trajectory of the lined wellbore with a drilling assembly consisting of a wellbore with lined pipe and a soil removal joint. A directional inclined drilling assembly is used at the same time as an earth removal joint. The lined pipe is sunk into the ground and the lined pipe in the wellbore, which was made by oblique drilling and sinking, remains in the wellbore. In one embodiment, the method consists of a number two wellbore with lined pipe where a part is placed substantially coaxially inside the wellbore's lined pipe.

[000308] In one embodiment, the present invention has a method of controlling the path of the lined wellbore with a drilling assembly consisting of a wellbore with lined pipe and a soil removal joint. A directional inclined drilling assembly is used at the same time as an earth removal joint. The lined pipe is sunk into the ground and the lined pipe in the wellbore, which was made by oblique drilling and sinking, remains in the wellbore. In addition, the drill assembly consists of a motor with a rotating axis. The rotating shaft has fluid passage through it. In another embodiment, the present invention has a method of controlling the trajectory of the lined wellbore with a drill assembly consisting of a wellbore with lined pipe and a soil removal joint. A directional inclined drilling assembly is used at the same time as an earth removal joint. The lined pipe is sunk into the earth and the lined pipe in the wellbore, which was made by slant drilling and sinking, remains in the wellbore and sinking where a locking joint operatively connects the soil removal joint to the wellbore's lined pipe.

[000309] In one embodiment, the present invention has the device for drilling a well, which consists of a motor-driven system in a motor-system housing, a shaft operatively connected to the motor-driven system and wherein the shaft has a passage and a diversion device located to be able to choose how the fluid flow is directed to the motor-driven system and the passage in the axis. In one method, the diversion assembly consists of a closing sleeve with one or more ports. The closing sleeve is placed in the axis. In another method, the diversion device consists of a rupture plate which is positioned to block the fluid flow to the passage in the axis.

[000310] In one embodiment, the present invention has a device for drilling a well consisting of a motor driven system in a motor system housing, a shaft operatively connected to the motor driven system and wherein the shaft has a passage and a diversion device located to be able to choose how the fluid flow is directed to the motor-driven system and the passage in the axis. In one method, the diversion assembly consists of a closing sleeve with one or more ports. The closing sleeve is placed in the axis. In another method, the diversion device consists of a rupture plate which is positioned to block the fluid flow to the passage in the axis. In one method, the engine driven system consists of a hydraulic system, while in another method a turbine system or a stator system is selected.

[000311] In one embodiment, the present invention has a device for drilling a well that consists of a motor driven system in a motor system housing, a shaft operatively connected to the motor driven system and wherein the shaft has a passage and a diversion device located to be able to choose how the fluid flow is directed to the motor-driven system and the passage in the axis and a drill shoe that is rotatably connected to a casing. The drill shoe consists of a rotatable drilling surface and a spindle which is connected to the axis. In one method, the drill shoe includes a fluid connection to the passage in the shaft. In another method, the drill shoe includes a shut-off mechanism to stop fluid flow through the fluid coupling.

[000312] In one embodiment, the present invention has a device for drilling a well consisting of a motor driven system in a motor system housing, a shaft operatively coupled to the motor driven system and wherein the shaft has a passage and a diversion device located to be able to choose how the fluid flow is directed to the motor-driven system and the passage in the shaft and a casing stopper is attached to the motor-driven system housing, the casing stopper is connected to a device to provide a releasable and secure connection to the inner surface of the casing. In one method, the casing consists of a nozzle placed at an angle by directional drilling of the casing. In another method, the casing consists of a stabilizer located near the center of the casing when directional drilling the casing. In yet another method, the casing stopper includes a fluid passage coupled to the passage in the shaft. In yet another method, the device also consists of a steering assembly which is connected to the casing stopper. The steering assembly has a conical part and a tubular part. In one method, the steering assembly includes one or more seats to receive a device selected from an intermediate string and an alignment device.

[000313] In one embodiment, the present invention has an apparatus for drilling a well comprising a motor-driven system in a motor-system housing, a shaft operatively coupled to the motor-driven system and wherein the shaft has a passageway and a diversion device which is positioned to be able to select how the fluid flow is directed to the motor driven system and the passage in the axis, where the motor system housing includes an expansion part to be able to increase the size of the casing.

[000314] Another embodiment of the present invention has a device which is used in drilling with casing and consists of a casing, a motor system which is placed in the casing and which can be pulled out, a motor system which consists that a motor-driven system which is placed in a motor system housing, a shaft operatively coupled to the motor-driven system, a shaft having a passageway and a diversion device positioned to select how fluid flow is directed to the motor-driven system and the passageway in the shaft and a bore surface operatively coupled to the axis of the engine system. In one method, the device also has a latch that is releasably attached to the casing and where the latch is fixed to the motor system.

[000315] Another embodiment of the present invention has a device which is used in drilling with casing and consists of a casing, a motor system which is placed in the casing and which can be pulled out, a motor system which consists that a motor-driven system which is placed in a motor system housing, a shaft operatively coupled to the motor-driven system, a shaft having a passageway and a diversion device positioned to select how fluid flow is directed to the motor-driven system and the passageway in the shaft and a bore surface operatively coupled to the axis of the engine system, where the diversion device consists of a closing sleeve with one or more ports and where the closing sleeve is located in the axis. Another embodiment of the present invention has a device for drilling is used in drilling with casing and consists of a casing, a motor system which is placed in the casing and which can be pulled out, a motor system which consists that a motor-driven system which is placed in a motor system housing , an axis operatively connected to the motor-driven system, an axis with a passage and a diversion device positioned to be able to select how the fluid flow is directed to the motor-driven system and the passage in the axis and a drilling surface operatively connected to the axis of the motor system, where the diversion device consists of a rupture plate which is positioned to block the fluid flow to the passage in the axis.

[000316] Another embodiment of the present invention has a device which is used in drilling with casing and consists of a casing, a motor system which is placed in the casing and which can be pulled out, a motor system which consists that a motor-driven system which is placed in a motor system housing, a shaft operatively connected to the motor-driven system, a shaft having a passageway and a diversion device positioned to select how fluid flow is directed to the motor-driven system and the passageway in the shaft and a bore surface operatively coupled to the axis of the engine system, where the engine driven system is a hydraulic system. Another embodiment of the present invention has a device used in drilling with casing and consists of a casing, a motor system which is located in the casing and which can be extracted, a motor system which consists of a motor driven system which is located in a motor system housing, an axis operatively connected to the motor-driven system, an axis having a passageway and a diversion device positioned to be able to select how fluid flow is directed to the motor-driven system and the passageway in the axis and a bore surface operatively connected to the axis of the motor system, wherein the motor-driven system consists of a system selected from a turbine system or a stator system.

[000317] In one embodiment of the present invention, a device used in drilling with casing and consisting of a casing, a motor system that is located in the casing and that can be pulled out, a motor system that consists that a motor-driven system that is located in a motor system housing, a shaft operatively connected to the motor-driven system, a shaft having a passageway and a diversion device positioned to select how fluid flow is directed to the motor-driven system and the passageway in the shaft and a bore surface operatively coupled to the axis of the motor system and a drill shoe which is rotatably connected to a casing. The drill shoe consists of a rotatable drilling surface and a spindle which is connected to the axis. In one method, the drill shoe includes a fluid connection to the passage in the shaft. In another method, the drill shoe includes a shut-off mechanism to stop fluid flow through the fluid coupling.

[000318] In one embodiment of the present invention, a device used in drilling with casing and consisting of a casing, a motor system that is located in the casing and can be pulled out, a motor system that consists that a motor-driven system that is located in a motor system housing, a shaft operatively coupled to the motor-driven system, a shaft having a passageway and a diversion device positioned to select how fluid flow is directed to the motor-driven system and the passageway in the shaft and a bore surface operatively coupled to the axis of the engine system and a casing lock that is attached to the engine driven system housing. The casing lock is connected to a device to provide a releasable and secure connection to the inner surface of the casing. In one method, the casing stopper includes a fluid passageway connected to the passageway in the shaft.

[000319] In one embodiment of the present invention, a device used in drilling with casing and consisting of a casing, a motor system that is located in the casing and can be pulled out, a motor system that consists that a motor-driven system that is located in a motor system housing, a shaft operatively connected to the motor-driven system, a shaft having a passageway and a diversion device positioned to select how fluid flow is directed to the motor-driven system and the passageway in the shaft and a bore surface operatively coupled to the axis of the motor system and a casing lock are attached to the motor-driven system housing. The casing stopper is connected to a device to provide a releasable and secure connection to the inner surface of the casing and a control assembly which is connected to the casing stopper. The steering assembly has a conical part and a tubular part. In one method, the steering assembly includes one or more seats for receiving a device selected from an intermediate string and an alignment device.

[000320] In one embodiment of the present invention, a device used in drilling with casing and consisting of a casing, a motor system that is located in the casing and can be pulled out, a motor system that consists that a motor-driven system that is located in a motor system housing, a shaft operatively coupled to the motor-driven system, a shaft having a passageway and a diversion device positioned to select how fluid flow is directed to the motor-driven system and the passageway in the shaft and a bore surface operatively coupled to the axis of the engine system there

the motor system housing includes an expansion section to increase the size of a casing.

[000321] Another embodiment of the present invention includes a method of drilling and completing a well consisting of pumping drilling mud to a motor system located in a casing, rotating a drilling surface coupled to the motor system, diverting fluid flow to a passage through the motor system and pump cement through the passage to the drill face. In one method, a releasable lock on the motor system is attached to the casing using a casing lock.

[000322] Another embodiment of the present invention includes a method of drilling and completing a well consisting of pumping drilling mud to a motor system located in a casing, rotating a drilling surface coupled to the motor system, diverting fluid flow to a passage through the motor system and pump cement through the passage to the drilling surface, where the drilling mud and cement are pumped using an intermediate string. Another embodiment of the present invention includes a method of drilling and completing a well which consists of pumping drilling mud to a motor system located in a casing, rotating a drilling surface coupled to the motor system, diverting the fluid flow to a passage through the motor system, pump cement through the passage to the drill face and extract the motor system from the casing.

[000323] Another embodiment of the present invention includes a method of drilling and completing a well consisting of pumping drilling mud to a motor system located in a casing, rotating a drilling surface coupled to the motor system, diverting fluid flow to a passage through the motor system, pump cement through the passage to the drill face and expand the casing using an extended section of the motor system housing.

[000324] Another embodiment of the present invention includes a method of starting and continuing a wellbore path consisting of a first casing having a soil removal joint driven from the lower end thereof, which penetrates a formation with the first casing to form a wellbore, where one can choose to change the trajectory of the wellbore while the formation is penetrated by the first casing and flows drilling fluid to a motor system located in the second casing. The second casing must be releasably attached to the inside diameter of the first casing and contain soil removal joint number two, rotate the second soil removal joint with the motor system and it must be possible to choose to change the path of the second casing as it is fed into the formation. In one method, the path of the second casing changes more than the path of the first casing.

[000325] The present invention also includes a method of altering the path of casing into a formation and consists of an outer casing having a releasable deflector attached to the lower end which penetrates the formation with the deflector, loosens the releasable attachment, bends the path on the outer casing in the formation by moving the casing string along the deflector, the inner casing detaches from a releasable attachment on the outer casing and flows drilling fluid to a motor system located inside the inner casing to rotate the soil removal joint operatively attached to the motor system, while a path is changed on the inner casing drilling into the formation. In another embodiment, the present invention also includes a device for bending a wellbore and consists of an outer casing with a joint used to bend the casing string in a desired direction. The first soil removal link is operatively connected to the lower end of the outer casing and an inner casing having a motor-driven system within it and located within the outer casing and operatively connected thereto.

[000326] The present invention also includes a method of changing the path of casing into a formation and consists of an outer casing having a releasable deflector attached to the lower end which penetrates the formation with the deflector, detaches the releasable attachment, bends the path on the outer casing in the formation by moving the casing string along the deflector, the inner casing detaches from a releasable attachment on the outer casing and flows drilling fluid to a motor system located inside the inner casing to rotate the soil removal joint operatively attached to the motor system, while a path is changed on the inner casing drilling into the formation. In another embodiment, the present invention also includes a device for bending a wellbore and consists of an outer casing with a link used to deflect the casing string in a preferred direction; a first soil removal link operatively connected to a lower end of the outer casing; and an inner casing having a motor driven system located within the outer casing and operatively attached thereto.

[000327] In yet another embodiment, the present invention includes a method of preferentially controlling a path of a casing to form a wellbore, which consists of providing a second casing concentrically located within a first casing having a skew joint, the second casing has a motor system releasably attached; jet drilling the first casing having an earth removal joint operatively connected into a formation to the first depth while selectively altering the path of the wellbore using the bevel joint, and triggering a releasable attachment between the first and second casing, providing drilling fluid to the motor system and changing selectively pathing the second casing while rotating an earth removal joint operatively coupled to a lower end of the motor system as the second casing continues into the formation. On the one hand, the bevel includes a preferred jet to direct fluid flow asymmetrically through the first casing while jet drilling. On the other hand, the inclined joint includes a stabilizing joint located near the midpoint of the first casing.

[00322] In another embodiment, this invention includes a method of routing a casing to form a wellbore, which comprises providing a second casing concentrically located within a first casing having a bevel joint. The second casing has a motor system releasably attached thereto and jet drills the first casing having an earth removal joint operatively connected into a formation to the first depth while selectively altering the trajectory of the wellbore using the bevel joint and actuating a releasable attachment between the first and the second casing, which supplies drilling fluid to the motor system, selectively alters a path of the second casing while rotating an earth removal joint operatively coupled to a lower end of the motor system as the second casing continues into the formation, diverting the fluid flow to a passage through the motor system. On the one hand, the method further comprises flowing a binder that can be changed physically, through the passage of the soil removal joint.

[00323] Yet another embodiment of this invention includes a method of preferentially routing a path of casing to form a wellbore consisting of providing a second casing concentrically located within a first casing having a skewed joint. The second casing has a motor system releasably attached which jet drills the first casing and has an earth removal joint operatively coupled into a formation to the first depth while selectively altering the path of the wellbore using the bevel joint, triggering a releasable attachment between the first and second casing, providing drilling fluid to the motor system and selectively changing a path of the second casing while rotating an earth removal joint operatively coupled to a lower end of the motor system while the second casing continues into the formation and drilling the second casing to the second depth and extending the second casing. On the one hand, the expansion of the second casing is achieved by extracting the motor system from the second casing.

[00324] In another embodiment, the present invention includes a method of preferentially routing a casing to form a wellbore, which comprises providing a second casing concentrically located within a first casing having a bevel joint. The second casing has a motor system releasably attached thereto and jet drills the first casing having an earth removal joint operably connected to a formation to a first depth while selectively changing the path of the wellbore using the inclined joint to actuate a releasable attachment between the first and second casing; providing drilling fluid to the motor system, selectively altering a path of the second casing while rotating an earth removal joint operatively coupled to a lower end of the motor system as the second casing continues into the formation; and extracting the engine system from the second casing.

[00325] This invention further includes, in one embodiment, a method of preferentially routing a path to a casing to form a wellbore, which consists of providing a second casing concentrically located within a first casing having a oblique joint. The second casing has a motor system releasably attached that jet drills the first casing, operatively connected to an earth removal joint, into a formation to a first depth while selectively altering the path of the wellbore using the bevel joint, triggering a releasable attachment between the first and second casing , provides drilling fluid to the motor system and selectively alters a path of the second casing while rotating a soil removal joint operatively coupled to a lower end of the motor system as the second casing continues into the formation and selectively introduces an inspection tool into the motor-driven system to selectively measure the path to the wellbore. On one side, the inspection tool selectively measures the trajectory of the wellbore while it is being drilled with the first and second casing.

[00326] In one embodiment, the present invention includes a method of preferentially routing a casing to form a wellbore, which consists of providing a second casing concentrically located within a first casing having a skew joint . The second casing has a motor system releasably attached, which jet drills the first casing, operatively connected to an earth removal joint, into a formation to a first depth while selectively changing the trajectory of the wellbore using the bevel joint, triggering a releasable attachment between the first and the second casing, provides drilling fluid to the motor system and selectively changes a path of the second casing while rotating an earth removal joint operatively coupled to a lower end of the motor system as the second casing continues into the formation, and measures a path to the wellbore while drilling with the first or second casing.

[00327] One embodiment of the present invention includes a wellbore deflection device consisting of a casing having upper and lower portions and a soil removal joint operatively attached to the lower end, and at least one hole opening blade located on the upper portion of the casing string to bending the casing with gravity to change a trajectory of the wellbore. The hole opening blade comprises on one side a concentric stabilizer. On the other hand, the hole opening blade is an eccentric stabilizer. Another embodiment of the present invention including a device for deflecting a wellbore, which consists of a casing having upper and lower parts and a soil removal joint operatively attached to the lower end and at least one hole opening blade located on the upper part of the casing string to deflect the casing by gravity to change the path of the wellbore, and at least one angled perforation in the soil removal joint to further change the path of the wellbore through asymmetric fluid flow through the perforation.

[00328] One embodiment of the present invention includes a method of deflecting a wellbore while being drilled with casing, which consists of a casing with a drill joint at the lower end that penetrates a formation with the casing while selectively changing a path to the casing and pumps drilling fluid to a motor system located in another casing located inside the casing which rotates the additional casing with the motor system. The motor system has an earth removal link operatively attached to the lower end, and selectively changes the direction of another casing to divert the wellbore on a further trajectory. Another embodiment includes a method of diverting a wellbore while being drilled with casing, which comprises providing a casing with a drill link on a lower end, providing a diverter link releasably attached to the drill link, anchoring the diverter link in the wellbore at a predetermined depth and to drive the drill bit along the diverters and thereby change the direction of the wellbore.

[00329] A further embodiment of the present invention includes a method of diverting a wellbore while drilling with casing, which consists of a casing with a drill joint on a lower end. The drilling joint has at least one extended fluid path; the fluid path is diverted from a centerline lengthwise on the string, and pumps fluid through the fluid path, thereby changing the direction of the wellbore. A further embodiment includes a method of diverting a wellbore while drilling with casing, which consists of forming a first larger diameter wellbore, providing a second lower wellbore of smaller diameter, and beveling a casing string to divert the lower end from the center line to the wellbore and thereby change the direction of the wellbore.

[00330] In another embodiment, the present invention includes a method for starting and making a continuous path of a wellbore, consisting of a casing string and a cutting device located in a lower part of the casing string, penetrating a formation with the casing string to forming the wellbore and selectively altering the path of the casing string as it continues into the formation. On the one hand, selective alteration of the path of the casing string consists of jet drilling fluid to create an asymmetric flow pattern through a lower portion of the cutter. On the other hand, selectively altering the path of the casing string consists of selectively diverting fluid flow out of a portion of the casing string. In one embodiment, selective diversion of fluid flow forms a profile in a portion of the formation through which the casing string continues.

[00331] An embodiment of the present invention includes a method for starting and making a continuous path to a wellbore, which consists of providing a casing and cutting device located in a lower part of the casing string, penetrating a formation with the casing string for forming the wellbore, and selectively altering the path of the casing string as it continues into the formation, the selectively altered path of the casing string laterally moving the casing string through an enlarged internal diameter in an upper portion of the wellbore. In another embodiment, the present invention includes a method of starting and continuing a path to a wellbore, which consists of providing a casing string and a cutting device located in a lower portion of the casing string, penetrating a formation with the casing string to form the wellbore and selectively changing the path of the casing string as it continues into the formation and inspecting the path of the wellbore while selectively changing the path of the casing string.

[00332] In a further embodiment, the present invention provides a method for starting and continuing a path to a wellbore, which consists of providing a casing string and a cutting device located in a lower part of the casing string, penetrating a formation with the casing string to forming the wellbore, selectively altering the path of the casing string as it continues into the formation and introducing at least one additional casing string into the casing string. In one embodiment, the present invention provides a method for starting and continuing a path to a wellbore, which consists of providing a casing string and a cutting device located in a lower portion of the casing string, penetrating a formation with the casing string to form the wellbore, and selectively changing the path of the casing string as it continues into the formation, wherein penetrating the formation with the casing includes jet drilling fluid through at least one nozzle located in the cutting device. The at least one nozzle has an expanded tubing diameter that is adjustable to vary the rate of penetration of the casing into the formation.

[00333] An embodiment of the present invention includes a path of a casing string in a formation, which consists of providing a casing string with a diverter releasably attached to the lower end, penetrating the formation with the diverter, tripping the releasable attachment and diverting the path of the casing string along the diverter. On one side, the deflector consists of an inclined wedge.

[00334] Another embodiment of the present invention includes a device for diverting a wellbore, which consists of a casing string with means to divert the casing string in a preferred direction and a first cutting device located in a lower part of the casing string. In one embodiment, the means for diverting the casing string in the preferred direction consists of an inclined wedge releasably attached to a lower part of the cutting apparatus. In another embodiment, the means for diverting the casing string in the preferred direction consists of an angled perforation through the lower part of the casing string to receive a fluid. In yet another embodiment, means for deflecting the casing string in a preferred direction further consist of a bent part of the casing string to deflect the casing string in a preferred direction. In another embodiment, means for deflecting the casing string in a preferred direction consist of a second cutting device placed on a part of the casing string above the first cutting device.

[00335] An embodiment of the present invention includes a device for diverting a wellbore, which consists of a casing string with means to divert the casing string in a preferred direction, a first cutting device located in a lower part of the casing string, and a landing pad for secure inspection tools there. In another embodiment, the present invention includes a device for diverting a wellbore consisting of a casing string with means for diverting the casing string in a preferred direction, and a first cutting device located in a lower part of the casing string, the casing string consisting of a lower casing string and an upper casing string, and where means for deflecting the casing string in a preferred direction consists of another cutting device which connects the lower casing string to the upper casing string and is larger in diameter than the second cutting device.

[00336] Another embodiment of the present invention includes a device for diverting a wellbore, which consists of a casing string with means to divert the casing string in a preferred direction, a cutting device located on a lower part of the casing string, and a drilling device releasably connected to an inner diameter of the casing string with another cutting device located on the drilling device below the releasable connection. On one side, the second cutting device consists of a cutting device located on a part facing the releasable connection.

[00337] An embodiment of the present invention includes a device for diverting a wellbore, which consists of a casing string with means to divert the casing string in a preferred direction, and a first cutting device located on a lower part of the casing string where the first cutting device includes at least one nozzle extending therethrough, and at least one nozzle having an elongated straight pipe diameter extending therethrough.

[00338] An embodiment of the present invention includes a device for diverting a wellbore, which consists of a casing string with means to divert the casing string in a preferred direction, and a first cutting device placed on a lower part of the casing string, the first cutting device including at least one nozzle extended therethrough, and the one nozzle having an elongated straight pipe diameter extended longitudinally through it. In one loading mode, at least one nozzle is drillable or made of soft material such as copper. In another embodiment, at least one nozzle consists of a thin coating of a hard substance. The substance has a hardness greater than the hardness of a soft material. The hard material can be ceramic or tungsten carbide. The remainder of the at least one nozzle may consist of a soft material such as copper

[00339] In another embodiment, the first cutting device includes at least one nozzle extending therethrough. At least one nozzle is drillable and has a profiled sleeve coating of a hard material. In another embodiment, the first cutting means includes at least one drillable nozzle extending therethrough. The at least one nozzle consists of a hard substance which has stressed parts for an increased possibility of breakage of the at least one nozzle when it is drilled through.

[00341] In another embodiment, the loaded parts include a plurality of notches extending in at least one nozzle. In yet another embodiment, a sealant is placed in the plurality of loaded notches.

[00341] In another embodiment, the present invention provides a die assembly that can be used into a tool body while a casing is being jet drilled into a formation. The nozzle assembly includes soft, drillable fabric forming a nozzle holder and a thin sleeve of a hard fabric placed inside the nozzle holder. The hard material forms an inner diameter extending past the exit and entry points of a fluid flow path through a hole through the tool body. The hard substance has a hardness greater than the hardness of the soft substance. In one embodiment, the soft substance is copper. In another embodiment, the hard material is ceramic. In yet another embodiment, the position of the thin sleeve is adjustable relative to the sleeve holder.

[00342] On the other hand, the present invention provides a method of directing, in a preferred manner, a path of a casing string to form a wellbore. The method includes jet drilling the casing string with a cutting device connected into a formation, and selectively directing the casing string in a direction as the casing string continues into the formation, In one embodiment, selectively routing the casing string consists of using the casing string to create an annular space in an upper portion of the wellbore and laterally routing an upper portion of the casing string through the annular space. In another embodiment, selective routing of the casing string consists of integrating arcs into the casing string to force the casing string to form the path in the wellbore while fluid is being routed asymmetrically out of the cutting device. In another embodiment, the casing string consists of a tubular body with an inclined wedge attached to the lower part, and where selective guidance of the casing string consists of guiding the path to the wellbore by blocking an axial path of the tubular body with the inclined wedge.

[00343] On the other hand, the present invention provides a device for diverting a wellbore. The device includes a casing string having upper and lower portions and at least one hole opening blade located on the upper portion of the casing string. In one embodiment, the device also includes a cutting device located on the lower portion of the casing string. In another embodiment, the device further includes a tubular body releasably connected to an inner diameter of the casing string, the tubular body having a cutting device located on the lower end comprising a cutting device located on upper and lower portions thereof.

[00344] On the other hand, the present invention provides a method of diverting a wellbore while drilling with casing. The method includes providing a casing string with a drill joint on a lower end, penetrating a formation with the casing string, and selectively changing a direction of the lower end to divert the wellbore.

[00345] On the other hand, the present invention provides an assembly for drilling with 30 casing. The assembly includes a casing lock to securely fasten the assembly to one of the casing, a bevel joint to provide the drill with a desired deflection from a centerline in the wellbore and at least one adjustable stabilizer. In one embodiment, the drill is an expandable drill. In another embodiment, the stabilizer has one or more support links adapted to be placed in a first position for driving through the position of the casing and a second position for contacting an inner wall of the wellbore. In yet another embodiment, the stabilizer is adjustable to at least a third position where an outer diameter of the stabilizer in the third position is smaller than the outer diameter of the stabilizer in the second position. In yet another embodiment, the assembly includes a flexible collar positioned between the drill bit and the casing stopper. In yet another embodiment, the inclined joint is a bent stand for a well motor adapted to drive the drill. In a further embodiment, the assembly includes a measuring tool adapted to measure a path for the wellbore and communicate the measured path to the wellbore surface. In another embodiment, the assembly includes at least one additional adjustable stabilizer. The drill can be a pilot bit. The drill may also include an extension drill.

[00346] On the other hand, the present invention provides a drilling assembly for creating wellbore, the drilling assembly has a casing part, a drilling assembly located on a lower end of the drilling assembly, the drilling assembly is adapted to be expanded from a first diameter to a second diameter, and at least one stabilizer is adapted to be adjusted from a first position to at least a second position. In one embodiment, the liner portion is expandable. In another embodiment, the drill assembly consists of an expandable drill bit. In yet another embodiment, the drill assembly consists of an inclined joint to provide the drill with a desired diversion from a center line in the wellbore. In yet another embodiment, the assembly includes a bevel joint to provide the drill assembly with a desired deflection from a centerline in the wellbore. In a further embodiment, the assembly includes a well drilling motor adapted to rotate the drill bit. In another embodiment, the assembly includes a flexible collar between the drill assembly and a lower end of the casing section. In yet another embodiment, the assembly also includes a measuring tool adapted to measure a path to the wellbore and communicate the measured path to the wellbore surface.

[00347] In one aspect, the present invention provides a method of drilling with casing. The method includes lowering a drilling assembly into a well hole through casing where the drilling assembly consists of an adjustable stabilizer and one or more drilling elements. The method also includes one or more support links for the stabilizer to increase a diameter of the stabilizer and driving the drilling assembly to expand a portion of the wellbore below the casing where the expanded portion has a diameter greater than an outer diameter of the casing. In one embodiment, the drilling elements may include an expandable drill bit to expand the expandable drill bit to have a larger outer diameter than the casing.

[00348] In another embodiment, the method may include measuring a path to the wellbore, and in response to the measured path, making one or more adjustments from the surface of the wellbore. The adjustments may involve adjusting the outrigger of the stabilizer or adjusting a weight applied to the drill. The method can also include the reading of a geophysical parameter.

[00349] In another embodiment, the method may include partially raising the drill assembly through the casing, pushing the casing forward into the extended portion of the wellbore, and raising the drill assembly through the casing to the surface of the wellbore.

[00350] On the other hand, the present invention provides a device for drilling a well hole in an earth formation. The device includes a drill string having a drill extending through it and a drill assembly connected to the lower end of the drill string. Preferably, the drill assembly is chosen so that it can be driven to form an inner diameter hole and at least partially be extractable through the inner diameter until the drill string elongates. The device may also include a directional wellbore drill assembly coupled to the drill string and includes inclined means for applying load to the drill assembly to drive it laterally relative to the wellbore and at least one adjustable stabilizer, the adjustable stabilizer being extendable through the wellbore extending to the drill string. In one embodiment, the adjustable stabilizer is placed over the bevel means of the directional wellbore drill assembly. In another embodiment, the drill assembly consists of an expandable drill selected to be drivable to form a wellbore having a diameter greater than the outer diameter of the drill string and to be extendable through the inner diameter until the drill string elongates.

[00351] On the other hand, the present invention provides a method for directional drilling of a well with casing as an extended tubular drill string and a drill assembly that can be withdrawn from the lower distal end of the drill string without withdrawing the drill string from a wellbore that becomes formed by the drilling assembly. The method includes providing the casing as the drill string, a directional wellbore drill assembly coupled to the drill string and including inclined means for applying load to the drill assembly to drive it laterally relative to the wellbore, and providing an adjustable stabilizer to support the directional drill assembly to the well hole. The method also includes connecting the drill assembly to the remote end of the drill string and inserting the drill string, the directional drill assembly and the drill 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 driving inclined means to drive the drill assembly laterally relative to the wellbore. The method further includes removing at least one part of the drill assembly from the remote end of the drill string, removing at least one part of the drill 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 links are adjusted to change a diameter of the stabilizer. In another embodiment, prior to removing at least a portion of the drill assembly from the distal end of the drill string, the method further includes partially raising at least a portion of the drill assembly through the drill string and advancing the drill string within the wellbore. [00352] On the other hand, the present invention provides an assembly for drilling with casing. The assembly includes a casing retainer to secure the assembly to a portion of the casing and a cutting device attached to a bottom portion of the assembly. The assembly also includes an inclined joint for providing the cutting device with a desired diversion from a centerline in the wellbore where biasing to provide the cutting device with the desired diversion is largely provided by the casing. In one embodiment, the inclined joint is an eccentric inclined pad located on an outer diameter of the casing. The eccentric inclined pad can change the centerline of the casing relative to the centerline of the casing relative to the centerline of the wellbore in the opposite direction from the side of the casing on which the eccentric inclined pad is placed. In another embodiment, the inclined joint consists of a bent motor stand inside the casing. The assembly may also include a concentric stabilizer located around a lower portion of the casing that absorbs the majority of the shear load. In yet another embodiment, the casing lock is a location lock. In yet another embodiment, the assembly includes at least one of a measurement under drilling tool and a resivity tool. In yet another embodiment, the cutting device is expandable. In yet another embodiment, the assembly is extractable from the casing.

[00353] On the other hand, the present invention provides a method of drilling with casing. The method includes providing a casing having an assembly releasably connected thereto. The assembly consists of an earth removal joint on the lower end and a slanting joint. The bevel joint deflects the soil removal joint to a desired angle with respect to the centerline of the wellbore and to place a bias load on the casing. In one embodiment, the method also includes a geophysical parameter. [00354] On the other hand, the present invention provides a method of forming a wellbore using a casing equipped with a cutting device. The method includes placing locating joints in the casing. the location link has a predetermined location relative to the cutting device, and an inspection tool with respect to the location link, such that a location of the inspection tool in the casing is known. In one embodiment, the placement member includes at least one flow aperture therethrough and the inspection tool includes at least one flow aperture therethrough. The placement link provides an additional functionality in the well such as receiving a cementing tool there or thereby obtaining an integrated step tool. In one embodiment, the locating member may include a slot. In another embodiment, the placement link may include a guide with a beveled edge profile and the inspection tool includes a matching guide with a beveled edge profile receptive to the guide with the beveled edge profile of the landing shoe. Steering with the beveled edge profiles of the inspection tool and the positioning link provides, after matching the steering with the beveled edge profiles, adaptation between the landing shoe and the inspection tool. In another embodiment, the location link includes a tubular member having a slot.

[00355] In another embodiment, the casing comprises a float shoe and the placement joint is located in the float shoe. In another embodiment, the inspection tool is placed by landing the inspection tool in the placement joint. In yet another embodiment, the method further includes obtaining information with respect to direction of the cutting device. The method may also include sending the information to a receiving device and controlling the cutting device in response to the received information. In another aspect, the cutting device includes a jet drilling assembly and/or a drill bit. In yet another embodiment, the method also includes removing the inspection tool before drilling is continued.

[00356] On the other hand, the present invention provides a device for monitoring a well where a drill string formed by a casing has a cutting device. The device includes an adjustment link placed in the drill string and an inspection tool receiveable in said adjustment link which can be adjusted by this to a desired location in the drill string. In one embodiment, the fitting member includes a shoe having a profile. The profile is rotationally indexed with respect to the circumference of the drill string. The inspection tool includes a customization element that is interactive with the shoe by local sering the inspection tool in the shoe to obtain a known fit of the inspection tool with the drill string. In another embodiment, the inspection tool includes a profile compatible with the profile of the matching member. In yet another embodiment, the fitting joint includes a slot, the inspection tool includes a generally cylindrical body having a fitting lug which protrudes, and the lug is positionable in the slot when the inspection tool is placed in the fitting joint to provide a known location of the inspection tool with the drill string.

[00357] In yet another embodiment, the inspection tool includes a generally hollow interior and an open end positionable in said fitting joint, and at least one aperture extending through the body of said inspection tool to communicate fluids from the casing to the hollow interior. The fitting joint includes an aperture extended therethrough to communicate fluid from an area above the fitting joint to an area below the fitting joint. The fitting joint otherwise blocks the communication of fluids through the drill string beyond it, and by means of this, after placing the inspection tool in the fitting joint for fitting thereof, fluids can pass through the aperture, and thus through the hollow interior of the inspection tool and through the fitting joint. In another mode of assessment, the inspection tool includes an inspection device positioned therein in a position so as not to interfere with fluid flow therethrough, and the inspection device may be operated to obtain wellbore or formation formation while fluids flow through it. In another embodiment, a drill bit has a drill motor and a jet drilling device is located at the end of the drill string, and the inspection tool controls the drill bit as the drill bit penetrates an earth formation.

[00358] In yet another embodiment, the fitting member includes a step tool and may further include a float tool to receive a lower float shoe for cementing therein.

[00359] On the other hand, the present invention provides an assembly for drilling with casing. The device includes a casing having a drill joint passed on a lower portion and a pivotable joint connecting the drill joint to the casing where the drill joint can pivot away from a centerline in the casing string for directional drilling. In one embodiment, the device further includes a drill motor where the pivot joint is connected to the drill motor.

[00360] On the other hand, the present invention provides an inspection tool for use while drilling with casing. The inspection tool includes a body having an inner diameter through it and one or more measuring devices. The inspection tool also includes an inlet for fluid communication between the casing and the inner diameter of the body and a bypass valve to divert fluid from the inlet. In one embodiment, the bypass valve is in a closed position when the fluid is at a low flow rate, while a higher flow rate puts the bypass valve in an open position.

[00361] On the other hand, the present invention provides a method for collecting information during casing drilling. The method includes a measuring tool in a casing, and the measuring tool has a first inlet and a second inlet. The method also includes flowing fluid through a first channel to activate the measurement tool and collect information about 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.

[00362] While the foregoing relates to embodiments of the present invention, other, further embodiments of the invention may be found without departing from the basic scope thereof, and the scope thereof is determined by the claims which follow.

Claims (26)

1. Earth removal joints including: a body having an internal cavity defined by a wall of the body and a fluid path through the wall of the body; a flow tube located inside the fluid path and having an inlet portion extending into the internal cavity and an outlet portion for ejecting fluid from the body, wherein the flow tube has a through bore; and a nozzle holder to hold the flow tube in the fluid path. 2. Earth removal joint according to claim 1, wherein an internal diameter of the flow pipe at one end is greater than an internal diameter of the flow pipe at another end. 3. Earth removal joint according to claim 1, in which the flow pipe is integrated with the nozzle holder. 4. Earth removal joint according to claim 1, in which a position of the flow pipe is adjustable with respect to the nozzle holder. 5. Soil removal joint according to claim 1, in which a low turbulence area is formed around an outside of the inlet portion of the flow pipe which extends into the internal cavity. 6. Earth removal joint according to claim 1, wherein a plurality of flow pipes are selectively operable to allow current therethrough. 7. Soil removal joint according to claim 1, in which the nozzle holder is at least partially located inside the flow path. 8. Earth removal joint according to claim 1, in which the length of the nozzle holder is shorter than a length of the wall of the body. 9. Earth removal joint according to claim 1, in which the holder is shorter than the flow pipe. 10. Earth removal joint according to claim 9, in which the holder is shorter than the wall of the body. 11. Soil removal joint according to claim 10, wherein an outside diameter of the flow pipe is sufficiently much smaller than an inside diameter of the flow path to form an annular gap therebetween. 12. Ground removal joint according to claim 1, wherein the outlet portion extends past an outer perimeter of the body. 13. Earth removal joint according to claim 1, wherein the outlet portion extends past an outer perimeter of the holder. 14. Soil removal joint according to claim 1, in which the flow pipe abuts a shoulder in the fluid path. 15. Earth removal joint according to claim 1, in which the flow pipe is oriented at an angle with respect to a vertical axis of the body. 16. Soil removal joint according to claim 1, in which a plurality of flow pipes are placed through the wall of the body. 17. A soil removal joint according to claim 1, wherein the flow pipe extends through a length of the nozzle holder. 18. Soil removal joint according to claim 1, in which the nozzle holder comprises a drillable material. 19. Soil removal joint according to crawling, in which the nozzle holder is releasably connected to the wall of the body. 20. Soil removal joint according to claim 1, in which the holder is made of a material that is softer than a material for the flow pipe. 21. Soil removal joint according to claim 1, wherein the entire length of the bore is substantially straight. 22. Soil removal joint according to claim 1, wherein the flow tube is made of a material that is more corrosion resistant than the nozzle holder. 23. Earth removal joint according to claim 1, wherein the flow pipe is made of a material selected from the group consisting of a ceramic material, tungsten carbide and polycrystalline diamond compact. 24. Ground removal joint according to claim 1, wherein the nozzle holder is made of a material selected from the group consisting of copper or plastic. 25. Soil removal joint according to claim 1, in which an annular cap is formed between the flow pipe and the flow path and is open to the internal cavity of the body. 26. Earth removal joint according to claim 1, further comprising a plurality of shears placed externally on the body.