Patent Publication Number: US-7708057-B2

Title: Coiled tubing wellbore drilling and surveying using a through the drill bit apparatus

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
   Priority is claimed from U.S. Provisional Application No. 60/844,604 filed on Sep. 14, 2006. 

   STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
   Not applicable. 
   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   The invention relates generally to the field of drilling and surveying wellbores through Earth formations. More specifically, the invention relates to methods for drilling and surveying a wellbore using coiled tubing. 
   2. Background Art 
   U.S. Patent Application Publication No. 2004/0118611 filed by Runia et al. describes methods and apparatus for drilling and surveying a wellbore in subsurface Earth formations in which a set of survey instruments is placed within a pipe or conduit used to convey a drill bit into the wellbore. The set of survey instruments is able to exit the interior of the pipe or conduit by a special tool causing a center segment of the drill bit to release, thus creating an opening for the survey instruments to leave the pipe or conduit and enter the wellbore below the bottom of the pipe or conduit. 
   The method and apparatus disclosed in the Runia et al. publication is intended to be used on so called “jointed” pipe, wherein a length of such pipe is made by threadedly assembling segments or “joints” of such pipe into a “string” extended into the wellbore. It is known in the art to carry out operations in a wellbore using so-called “coiled tubing.” In coiled tubing operations, a reel of tubing is transported to the wellbore site. Wellbore tools of various types, including drilling tools, are affixed to the end of the coiled tubing, and the coiled tubing is unwound from the reel so as to extend into the wellbore. Coiled tubing wellbore operations have advantages such as much faster time to exchange wellbore tools by retrieving the coiled tubing from the wellbore by spooling the coiled tubing back onto the reel. Such winding is considerably faster than uncoupling the threaded connections used with conventional threadedly coupled pipe. There is a need to have wellbore drilling and surveying techniques as disclosed in the Runia et al. publication that are usable with coiled tubing. 
   SUMMARY OF THE INVENTION 
   In a method according to one aspect of the invention, a wellbore is drilled and surveyed using coiled tubing. A method according to this aspect of the invention includes unspooling a coiled tubing into a wellbore to a selected depth therein. When the tubing is at the selected depth, the tubing is uncoupled and in some embodiments a section of coiled tubing containing a latched tool is inserted into the coiled tubing. In other embodiments, the tool is inserted into the uncoupled tubing. The tubing is reconnected, and the tool is detached from the coiled tubing and is moved along the interior of the tubing. 
   In one embodiment, the tool causes a center drill bit section to become unlatched from the tubing. The tool is then moved at least in part into the wellbore below the portion of the drill bit remaining attached to the coiled tubing string. The entire drill bit or drilling assembly may be released in another embodiment. 
   Other aspects and advantages of the invention will be apparent from the following description and the appended claims. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a schematic partially cross-sectional side view of an apparatus embodying principles of the present invention. 
       FIG. 1A  shows elements of a well pressure control system and coiled tubing operating devices in more detail. 
       FIG. 2  is an elevational view of a tubing reel utilized in the apparatus of  FIG. 1 . 
       FIGS. 3-5  are side elevational views of alternate connector systems utilized in the apparatus of  FIG. 1 . 
       FIG. 6  is a quarter-sectional view of a first connector. 
       FIG. 7  is a quarter-sectional view of a second connector. 
       FIG. 8  is an enlarged cross-sectional view of an alternate seal structure for use with the second connector. 
       FIG. 9  is a partially cross-sectional view of a sensor apparatus embodying principles of the present invention. 
       FIG. 10  is a schematic partially cross-sectional side view of a variation of the apparatus of  FIG. 1 . 
       FIG. 10A  shows another embodiment of tool assembly in a segment of tubing. 
       FIG. 11  shows a schematic overview of an embodiment of a through the bit system. 
       FIG. 12  shows a schematic drawing of the MWD/LWD survey system of  FIG. 11 . 
       FIG. 13  shows a schematic drawing of the drill steering system of  FIG. 11 . 
       FIG. 14  shows a schematic drawing of the drill bit of  FIG. 11 . 
       FIG. 15  shows a schematic drawing of logging tool that has been passed through the bottom hole assembly to extend into the wellbore ahead of the drill string. 
       FIG. 16  shows a mud motor having a releasable rotor or rotor and stator combination to enable movement of wellbore logging instruments below the bottom of the coiled tubing into the open wellbore. 
       FIG. 17  shows one embodiment of an annular mud motor that may be used in accordance with the invention. 
       FIG. 18  shows an alternative embodiment in which wellbore logging sensors remain within the tubing string during operation. 
       FIGS. 19 and 20  show an embodiment of a coaxial, dual coiled tubing. 
       FIGS. 21 and 22  show embodiments of side by side dual coiled tubing. 
       FIGS. 23 and 24  show additional embodiments of a side by side coiled tubing. 
       FIG. 25  shows an example of a tool assembly that can be assembled from a plurality of housing segments. 
   

   DETAILED DESCRIPTION 
   The principle of inserting various types of wellbore instruments into a coiled tubing according to the present invention may use, in some embodiments, a method and apparatus disclosed in U.S. Pat. No. 6,561,278 to Restarick et al., incorporated herein by reference.  FIG. 1  shows an apparatus  10  which embodies principles of such apparatus and methods. In the following description of the apparatus  10 , and with respect to other apparatus and methods described herein, directional terms, such as “above”, “below”, “upper”, “lower”, etc., are used only for convenience in referring to the accompanying drawings and are not intended to limit the scope of the invention to any specific relative placement of the various components described herein. Additionally, it is to be understood that the various embodiments described herein may be used in wellbores having various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without exceeding the scope of what has been invented. 
   In the apparatus  10 , a continuous tubing string  12  known in the art is deployed into a wellbore by unwinding it from a reel  14 . Since the tubing string  12  is initially wrapped on the reel  14 , such continuous tubing strings are commonly referred to as “coiled tubing” strings. As used herein, the term “continuous” means that the tubing string is deployed substantially continuously into a wellbore, allowing for some interruptions to interconnect certain tool assemblies therein, as opposed to the manner in which segmented or “jointed” tubing is deployed into a wellbore by threadedly coupling together individual “joints” or “stands” limited in length by the height of a rig supporting structure (“derrick”) at the wellbore. 
   The vast majority of the tubing string  12  consists of tubing  16 . The tubing  16  may be made of a metallic material, such as steel, or it may be made of a nonmetallic material, such as a composite material, including, for example, fiber reinforced plastic. As described below connectors in the tubing string permit tool assemblies to be inserted into the interior of the tubing string  12  for movement to the bottom of the tubing string  12  and/or beyond the bottom thereof. 
   In the apparatus  10 , wellbore tool assemblies  18  (a packer),  20  (a valve),  22  (a sensor apparatus),  24  (a wellbore screen) and  26  (a spacer or blast joint) can be interconnected in the tubing string  12  without requiring splicing of the tubing  16  at the wellbore, and without requiring the tool assemblies to be wrapped on the reel  14 . In the present invention, connectors  28 ,  30  are provided in the tubing string  12  above and below, respectively, each of the tool assemblies  18 ,  20 ,  22 ,  24 ,  26 . These connectors  28 ,  30  are included into the tubing string  12  prior to, or as, it is being wrapped on the reel  14 , with each connector&#39;s position in the tubing string  12  on the reel  14  corresponding to a desired location for the respective tool assembly in the wellbore. 
   The tool assemblies  18 ,  20 ,  22 ,  24 ,  26  may also be various forms of wellbore logging (formation evaluation) and drilling sensors, including but not limited to acoustic sensors, natural or induced gamma radiation sensors, electromagnetic and/or galvanic resistivity sensors, gamma-gamma (photon backscatter) density sensors, neutron porosity and/or capture cross section sensors, formation fluid testers, mechanical stress sensors, mechanical properties sensors or any other type of wellbore logging and formation evaluation sensor known in the art. Such sensors may include batteries (not shown) or turbine generators (not shown) for electrical power. Signals detected by the various sensors may be stored locally in a suitable recording medium (not shown) in each tool assembly, or may be communicated to the Earth&#39;s surface using suitable telemetry, such as mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, electrical telemetry along a cable inside or outside the tubing string  12  or in cases where the tubing string  12  is made from a composite material having electrical lines therein, as will be explained in more detail below, telemetry can be applied to the electrical lines for detection and decoding at the Earth&#39;s surface. Signals, such as operating commands, or data, may also be communicated from the Earth&#39;s surface to the tool assemblies in the well using any known type of telemetry. 
   The connectors  28 ,  30  are placed in the tubing string  12  at appropriate positions, so that when the tool assemblies  18 ,  20 ,  22 ,  24 ,  26  are interconnected to the connectors  28 ,  30  and the tubing string  12  is deployed into the wellbore, the tool assemblies  18 ,  20 ,  22 ,  24 ,  26  will be disposed at their respective desired locations in the wellbore. In the case of wellbore logging sensors, the coiled tubing may be extended into the wellbore and/or retracted from the wellbore in order to make a record of the various sensor measurements with respect to depth in the wellbore. 
   The tubing string  12  with the connectors  28 ,  30  therein is wrapped on the reel  14  prior to being transported to the wellbore. At the wellbore, the tool assemblies  18 ,  20 ,  22 ,  24 ,  26  are interconnected between the connectors  28 ,  30  as the tubing string  12  is deployed into the wellbore from the reel  14 . In this manner, the tool assemblies  18 ,  20 ,  22 ,  24 ,  26  do not have to be wrapped on the reel  14  or be transported around the gooseneck (G in  FIG. 1A ). 
   Equipment usually used with coiled tubing in wellbore operations is shown schematically in  FIG. 1A . The wellbore includes at least a surface casing C cemented therein. The uppermost end of the casing C typically will be coupled to a blowout preventer BOP or similar wellbore fluid pressure control device. The blowout preventer BOP includes “shear rams” SR or similar device capable of closing the wellbore by shearing through the tubing  16  or other device disposed within the opening of the blowout preventer BOP. The blowout preventer BOP may include an annular pressure control device APC that seals around the exterior of the tubing  16 , such as one sold under the trademark HYDRIL, which is a registered trademark of Hydril Company, Houston, Tex. The tubing  16  is moved into and out of the wellbore by one or more tubing injectors  11 ,  12  of types well known in the art. The tubing injectors  11 ,  12  may have different diameters if the tubing includes upset diameter elements therein, such as the connectors ( 28 ,  30  in  FIG. 1 ). The tubing  16  is gradually bent to extend along the longitudinal axis of the wellbore by passing over a gooseneck G, which may include a plurality of rollers R or the like to enable to tubing  16  to move over the gooseneck G with minimal friction. 
   Referring to  FIG. 2 , a view of the reel  14  is shown in which the connectors  28 ,  30  are wrapped with the tubing  16  on the reel  14 . In the view of  FIG. 2  it may be clearly seen that the connectors  28 ,  30  are interconnected to the tubing  16  prior to the tubing  16  being wrapped on the reel  14 . As described above, the connectors  28 ,  30  are positioned to correspond to desired locations of particular tool assemblies in a wellbore Placeholders  38  can be used to substitute for the respective tool assemblies between the connectors  28 ,  30  when the tubing  16  is wrapped on the reel  14 . 
   Referring to  FIGS. 3-5 , various alternate connector systems  32 ,  34 ,  36  are representatively illustrated. In the system  32  depicted in  FIG. 3 , both of the connectors  28 ,  30  are male-threaded, and so a placeholder  40  used to connect the connectors  28 ,  30  together while the tubing string  16  is on the reel  14  has opposing female threads. In some embodiments, a will be explained in more detail below with reference to  FIG. 10A , a segment  159  of tubing with a logging tool  160  attached or latched to the inside is inserted into the tubing string  12  when the connectors ( 28 ,  30  in  FIG. 1 ) are uncoupled. Other embodiments may provide that the tool assembly is inserted directly into the interior of the tubing string  12  directly without the need to an additional segment  159  of tubing. In the system  34  depicted in  FIG. 4 , the connector  28  has male threads, the connector  30  has female threads, and so a placeholder  42  has both male and female threads. In the system  36  depicted in  FIG. 5 , no placeholder is used. Instead, the male-threaded connector  28  is directly connected to the female-threaded connector  30  when the tubing  16  is wrapped on the reel  14 . 
   Thus, it may be observed that a variety of methods may be used to provide the connectors  28 ,  30  in the tubing string  12 . Of course, it is not necessary for the connectors  28 ,  30  to be threaded, or for any particular type of connector to be used. Any connector may be used in the apparatus  10 , without exceeding the scope of this invention. If the tubing segment ( 159  in  FIG. 10A ), connectors ( 28 ,  30  in  FIG. 1 ) and tool assembly  160  introduce an upset in the tubing diameter, it may be advantageous to utilize two injector assemblies ( 11 ,  12  in  FIG. 1A ) or one injector assembly capable of accommodating tubing with different diameters. See, for example, Tubel, U.S. Pat. No. 6,082,454 and/or Rosine, U.S. Pat. No. 6,834,734 to facilitate movement of the tubing string  12 . It may also be possible to use, as an alternative to the coupling technique described with reference to  FIG. 1 , a fusion bonding method, as practiced by TubeFuse Technologies Ltd., Kings Park, Fifth Avenue, Team Valley, Gateshead, Tyne and Wear, United Kingdom NE11 0AF. Alternatively, the connectors ( 28 ,  30  in  FIG. 1 ) may be made from high strength material such as titanium or other high strength alloy, such that the connectors  28 ,  30  and/or tubing segment ( 159  in  FIG. 10A ) do not introduce upsets into the tubing string  12  diameter. Still another alternative is to join the tubing segments using a so-called “roll on” or “crimp on” connector. Such connectors include a profiled insert with external seals that fits into the open ends of separated tubing string. A crimping or rolling device then compresses the tubing onto the connector to seal the ends and to provide mechanical coupling between the tubing ends. One such connector is sold by Schlumberger Technology Corporation, Sugar Land, Tex. and is identified as a “roll-on” connector. 
   Referring to  FIG. 6 , another embodiment of a connector  44  is shown. The connector  44  may be used in substitution of the connector  28  or  30  in the apparatus  10 , or it may be used in other apparatus. The connector  44  is configured for use with a composite tubing  46 , which has one or more lines  48  embedded in a sidewall thereof. A slip, ferrule or serrated wedge  50 , or multiple ones of these, is used to grip an exterior surface of the tubing  46 . The slip  50  is biased into gripping engagement with the tubing  46  by tightening a sleeve  58  onto a housing  60 . A seal  52  seals between the exterior surface of the tubing  46  and the sleeve  58 . Another seal  54  seals between an interior surface of the tubing  46  and the housing  60 . A further seal  62  seals between the sleeve  58  and the housing  60 . In this manner, an end of the tubing  46  extending into the connector  44  is isolated from exposure to fluids inside and outside the connector. A barb  56  or other electrically conductive member is inserted into the end of the tubing  46 ,  50  that the barb  56  contacts the line  48 . A potting compound  72 , such as an epoxy, may be used about the end of the tubing  46  and the barb  56  to prevent the barb  56  from dislodging from the tubing  46  and/or to provide additional sealing for the electrical connection. Another conductor  64  extends from the barb  56  through the housing  60  to an electrical contact  66 . The barb  56 , conductor  64  and contact  66  thus provide a means of transmitting electrical signals and/or power from the line  48  to the lower end of the connector  44 . Shown in dashed lines in  FIG. 6  is a mating connector or tool assembly  68 , which includes another electrical contact  70  for transmitting the signals/power from the contact  66  to the connector or tool assembly  68 . 
   Although the line  48  has been described above as being an electrical line, it will be readily appreciated that modifications may be made to the connector  44  to accommodate other types of lines. For example, the line  48  could be a fiber optic line, in which case a fiber optic coupling may be used in place of the contact  66 , or the line  48  could be a hydraulic line, in which case a hydraulic coupling may be used in place of the contact  66 . In addition, the line  48  could be used for various purposes, such as communication, chemical injection, electrical or hydraulic power, monitoring of downhole equipment and processes, and a control line for, e.g., a safety valve, etc. Of course, any number of lines  48  may be used with the connector  44 , without exceeding the scope of what has been invented. 
   Referring to  FIG. 7 , an upper connector  74  and a lower connector  76  embodying principles of the present invention are shown. These connectors  74 ,  76  may be used in substitution of the connectors  28 ,  30  in the apparatus  10  of  FIG. 1 , or they may be used in any other apparatus. 
   The connectors  74 ,  76  are designed for use with a composite tubing  78 . The tubing  78  has an outer wear layer  80 , a layer  82  in which one or more lines  84  is embedded, a structural layer  86  and an inner flow tube or seal layer  88 . This tubing  78  may be a composite coiled tubing sold under the trademark FIBERSPAR, which is a registered trademark of Fiberspar Corporation, Northwoods Industrial Park West, 12239 FM 529, Houston, Tex. 77041. One or more lines  90  may also be embedded in the seal layer  88 . 
   The wear layer  80  provides abrasion resistance to the tubing  78 . The structural layer  86  provides strength to the tubing  78 . The layers  82 ,  88  isolate the structural layer  86  from contact with fluids internal and external to the tubing  78 , and provide sealed pathways for the lines  84 ,  90  in a sidewall of the tubing  78 . Thus, if the lines  84 ,  90  are electrical conductors, the layers  82 ,  88  provide insulation for the lines. Of course, any type of line may be used for the lines  84 ,  90 , without exceeding the scope of the invention. 
   The upper connector  74  includes an outer housing  92 , a sleeve  94  threaded into the housing  92 , a mandrel  96  and an inner seal sleeve  98 . The upper connector  74  is sealed to an end of the tubing  78  extending into the upper connector  74  by means of a seal assembly  100 , which is compressed between the sleeve  94  and the housing  92 , and by means of sealing material  102  carried externally on the inner seal sleeve  98 . 
   The mandrel  96  grips the structural layer  86  with multiple collets  104 , only one of which is visible in  FIG. 7 , having teeth formed on inner surfaces thereof. Multiple inclined surfaces are formed externally on each of the collets  104 , and these inclined surfaces cooperate with similar inclined surfaces formed internally on the housing  92  to bias the collets  104  inward into engagement with the structural layer  86 . A pin  106  prevents relative rotation between the mandrel  96  and the tubing  78 . 
   The line  84  extends outward from the layer  82  and into the upper connector  74 . The line  84  passes between the collets  104  and into a passage  108  formed through the mandrel  96 . At a lower end of the mandrel  96 , the line  84  is connected to a line connector  110 . If the line  90  is provided in the seal layer  88 , the line  90  may also extend through the passage  108  in the mandrel  96  to the line connector  110 , or to another line connector. 
   The line connector  110  is depicted as being a pin-type connector, but it may be a contact, such as the contact  66  described above, or it may be any other type of connector. For example, if the lines  84 ,  90  are fiber optic or hydraulic lines, then the line connector  110  may be a fiber optic or hydraulic coupling, respectively. 
   When the connectors  74 ,  76  are connected to each other, an annular projection  112  formed on a lower end of the inner seal sleeve  98  initially sealingly engages an annular seal  114  carried on an upper end of an inner sleeve  116  of the lower connector  76 . Further tightening of a threaded collar  118  between the housing  92  and a housing  120  of the lower connector  76  eventually brings the line connector  110  into operative engagement with a mating line connector  122  (shown in  FIG. 7  as a socket-type connector) in the lower connector  76 , and then brings an annular projection  124  into sealing engagement with an annular seal  126  carried on an upper end of the housing  120 . The seals  114 ,  126  isolate the line connectors  110 ,  122  (and the interiors of the connectors  74 ,  76 ) from fluid internal and external to the connectors. 
   Since the lower connector  76  is otherwise similarly configured to the upper connector  74 , it will not be further described herein. Note that both of the connectors  74 ,  76  may be connected to tool assemblies, such as the tool assemblies  18 ,  20 ,  22 ,  24 ,  26 , so that connections to lines may be made on either side of each of the tool assemblies. Thus, the lines  84 ,  90  may extend through each of the tool assemblies from a connector above the tool assembly to a connector below the tool assembly. This functionality is also provided by the connector  44  described above. 
   Referring to  FIG. 8 , an alternate seal configuration  128  is representatively illustrated. The seal configuration  128  may be used in place of either the projection  112  and seal  114 , or the projection  124  and seal  126 , of the connectors  74 ,  76 . 
   The seal configuration  128  includes an annular projection  130  and an annular seal  132 . However, the projection  130  and seal  132  are configured so that the projection  130  contacts shoulders  134 ,  136  to either side of the seal  132 . This contact prevents extrusion of the seal  132  due to pressure, and also provides metal-to-metal seals between the projection  130  and the shoulders  134 ,  136 . 
   Referring to  FIG. 9 , an example is shown of a tool assembly  138  which may be interconnected in a continuous tubing string. The tool assembly  138  is a sensor apparatus. It includes sensors  140 ,  142 ,  144 ,  146  interconnected to lines  148 ,  150  embedded in a sidewall material of a tubular body  152  of the tool assembly  138 . 
   The sensors  140 ,  142 ,  144 ,  146  are also embedded in the sidewall material of the body  152 . The sensors  140 ,  142 ,  144  sense parameters internal to the body  152 , and the sensor  146  senses one or more parameter external to the body  152 . Any type of sensor may be used for any of the sensors  140 ,  142 ,  144 ,  146 . For example, pressure and temperature sensors may be used. It would be particularly advantageous to use a combination of types of sensors for the sensors  140 ,  142 ,  144 ,  146  which would allow computation of values, such as multiple phase flow rates through the tool assembly  138 . 
   As another example, it would be advantageous to use a seismic sensor for one or more of the sensors  140 ,  142 ,  144 ,  146 . This would make available seismic information previously unobtainable from the interior of a sidewall of a tubing string. 
   Note that when using certain types of sensors, the sidewall material is preferably a nonmetallic composite material, but other types of materials may be used in keeping with the principles of the invention. In particular, the body  152  could be a section of composite tubing, in which the sensors  140 ,  142 ,  144 ,  146  have been installed and connected to the lines  148 ,  150 . 
   The lines  148 ,  150  may be any type of line, including electrical, hydraulic, fiber optic, etc. Additional lines (not shown in  FIG. 9 ) may extend through or into the tool assembly  138 . Connectors  154 ,  156  permit the tool assembly  138  to be conveniently interconnected in a tubing string. For example, the connector  76  described above may be used for the connector  154 , and the connector  74  described above may be used for the connector  156 . Via the connectors  154 ,  156 , the lines  148 ,  150  are connected to lines extending through tubing or other tool assemblies attached to each end of the tool assembly  138 . 
   Referring to  FIG. 10 , the apparatus  10  is shown wherein a tool assembly  160  is being inserted into the interior of the tubing string  12 . The tool assembly  160  may be too long, too rigid, or too large in diameter to be wrapped on the reel  14  with the tubing  16 . In the present embodiment, the tool assembly  160  may be a set of wellbore logging or formation evaluation sensors disposed in a single housing adapted to traverse the interior of the tubing string  12 , and as will be further explained below with reference to  FIGS. 11 through 15 , in some embodiments may at least partially exit through a special opening in a drill bit disposed at the end of the tubing string  12 . The sensors measure one or more parameters related to the ambient environment inside or outside the tubing string  12 , and may include, for example, gamma radiation, density, neutron capture cross section, acoustic velocity, pressure, temperature, electrical resistivity and any other parameter of interest related to the tubing string  12 , the wellbore or the surrounding subsurface formations. 
   The connectors  28 ,  30  are separated, and a placeholder  38  (if used) is removed prior to inserting the tool assembly  160  into interior of the tubing string  12 . The tool assembly  160 , and in some embodiments inside tubing segment ( 159  in  FIG. 10A ), may be lifted by a cable supported by a crane, mast unit or derrick known in the art for supporting sheave units used with electrical wireline or slickline deployment systems. The tool assembly  160  inside the tubing segment ( 159  in  FIG. 10A ) in some embodiments is inserted into the tubing string  12 , the lower connector  30  is reconnected to the upper connector  28 , and the tubing string  12  is extended into the wellbore. As described above, the connectors  28 ,  30  are provided already connected to the tubing  16  when the tubing  16  is wrapped on the reel  14  and transported to the wellbore. Thus, a long tool assembly may be inserted into the interior of the tubing string without the need to wrap in on the reel  14  or go around the gooseneck (G in  FIG. 1A ). The tool assembly  160  may include a latch or similar releasable restraining device (not shown) to hold the tool assembly  160  in its longitudinal position in the tubing string  12 , and in some embodiments tubing segment  159  inserted into the tubing string  12 , until which time it is desired to move the tool assembly  160  downward in the tubing string  12 . Such latch may be released by pumping a small release tool or the like through the interior of the tubing string  12 , inserted at the surface end of the tubing string  12  at the reel  14 . Other examples of releasing devices are described below with reference to  FIG. 10A . 
   In  FIG. 10A , some embodiments of a tool assembly  160  may provide that the tool assembly  160  is initially disposed in an insertable segment  159  of tubing. The insertable segment  159  may include connectors  28 A,  30 A at its longitudinal ends such that the segment  159  may be coupled to the tubing string ( 12  in  FIG. 10 ) substantially as connecting together the upper and lower ends of the separated tubing string in other embodiments. The tool assembly  160  may be coupled to the interior of the segment  159  by one or more types of latch  161 . The latch  161  in this embodiment and on other embodiments may be operated by any means known in the art, including but not limited to, for example, “pigging”, fluid pressure, or electromagnetic or other signal from outside the tubing string  12 . 
   Referring to  FIG. 25 , in some embodiments, the tool assembly  160  may consist of a plurality of housing segments, shown generally at  1000 ,  1002 ,  1004 ,  1006  and  1008  having longitudinal dimension short enough and/or being flexible enough to enable movement of the segments inside the tubing string ( 12  in  FIG. 10 ) while it is still on the reel ( 14  in  FIG. 10 ). The housing segments  1000 ,  1002 ,  1004 ,  1006 ,  1008  may be made from steel, titanium or other high strength metal, or from fiber reinforced plastic, for example. The housing segments, when moved into contact with each other may make electrical connection between them using a submersible electrical connector such as one sold by Kemlon Products and Development, Houston, Tex. The male portions of such connectors are shown at  1005  at the top of each of housing segments  1008 ,  1006 ,  1004  and  1002 . Female portions of such connectors are shown at  1009  at the bottom of housing segments  1000 ,  1002 ,  1004  and  1006 . In the present embodiment, the uppermost housing segment  1000 , which is the last to be inserted into the tubing string ( 12  in  FIG. 1 ) if inserted by opening the tubing string at or near the Earth&#39;s surface, may include a power supply and signal processing and storage elements (not shown separately), and in some embodiments a gamma radiation sensor or spectral gamma radiation sensor  1010 . The uppermost housing segment  1000  may also include a fishing neck  1001  at the upper end thereof to enable retrieval of all or part of the tool assembly  160  using slickline or wireline passed through the tubing string ( 12  in  FIG. 1 ). The tool assembly  160  may also be retrieved by reverse pumping fluid into the bottom of the tubing string ( 12  in  FIG. 1 ). The housing segments  1000 ,  1002 ,  1004 ,  1006  may each be coupled to the adjacent, lower housing segment  1002 ,  104 ,  1006 ,  1008  in the tool assembly  160  when contacted with such housing segment by spring loaded collets  1003  extending from the bottom of each such housing segment  1000 ,  1002 ,  1004 ,  1006  to be joined. The upper portion of each housing segment to be joined by the collets  1003  from the housing segment above may include an internal groove on an upper shoulder  1018  to receive and latch the collets  1003 . 
   The second tool housing segment  1002  may include a radiation source, sensors and detection circuitry, for example, for a neutron porosity sensing device  1015 . Compensated neutron devices are described, for example in U.S. Pat. No. 4,035,639 issued to Boutemy et al., incorporated herein by reference. 
   The next housing segment  1004  may include acoustic transducers  1017  for making various measurements of acoustic properties of the Earth formations penetrated by the wellbore. The next housing segment  1006  may include a gamma radiation backscatter density sensor  1019  that typically includes a gamma radiation source and two spaced apart gamma radiation detectors. Some density sensors may also detect photoelectric effect to provide an indication of the mineral composition of the Earth formations surrounding the wellbore. The next housing segment  1008  may include antennas  1007  and corresponding circuitry (not shown separately) for making electromagnetic induction conductivity measurements of the Earth&#39;s formations surrounding the wellbore. The order in which the segments are assembled as shown in  FIG. 25  is only an illustration of one possible arrangement of sensors and is not a limit on the scope of this aspect of the invention. 
   To deploy such a tool assembly  160  as shown in  FIG. 25 , the housing segments  1008 ,  1006 ,  1004 ,  1002 ,  1000  may be inserted into the interior of the tubing string ( 12  in  FIG. 1 ) one at a time at the surface end of the reel ( 14  in  FIG. 1 ). Fluid may then be pumped through the interior of the tubing string ( 12  in  FIG. 1 ) to move the housing segments  1008 ,  1006 ,  1004 ,  1002 ,  1000  in the direction of the bottom end of the tubing string ( 12  in  FIG. 1 ). A restriction, latch, muleshoe sub or similar device  1016  may be disposed at a selected position along the tubing string ( 12  in  FIG. 1 ), one such position for example, as explained further below with reference to  FIG. 18 . When the housing segments, starting with segment  1008 , reach the device  1016 , a key  1012  on the lower segment  1008  may seat in a corresponding opening  1014  in the device  1016 . As each successive segment  1006 ,  1004 ,  1002 ,  1000  reaches the upper end of the succeeding segment in the tool assembly  160 , the collets  1003  will latch in the corresponding groove  1018  in the next housing segment. When the last housing segment  1000  reaches the second housing segment  1002  the tool assembly  160  will be fully assembled. 
   As an alternative to using the submersible electrical connectors  1005 ,  1009  shown in  FIG. 25 , only a mechanical connection between segments, such as collets  1003  and grooves  1004 , may be used. Sensor and other instrument signals and/or electrical power may be transferable between the housing segments using electromagnetic inductive couplings. See, for example, Veneruso, U.S. Pat. No. 5,521,592 for one implementation of an electromagnetic coupling. The assembled tool assembly  160  may then be operated in its ordinary manner, including for example, making a record of parameter measurements as the tubing string ( 12  in  FIG. 1 ) is extended further into the wellbore, including during additional drilling of the wellbore, and/or as the tubing string ( 12  in  FIG. 1 ) is withdrawn from the wellbore. Such operation may take place entirely within the tubing string ( 12  in  FIG. 1 ) as well as by extending the tool assembly  160  part or all the way out of the bottom of the tubing string ( 12  in  FIG. 1 ) in a manner to be further explained below. 
   The description which follows is related to a method and device shown in U.S. Patent Application Publication No. 2004/0118611 filed by Runia et al. and incorporated herein by reference. Such method and apparatus as disclosed in the &#39;611 publication is described therein as being used in a tubing string that is assembled from threadedly coupled tubing segments. In the invention, such method and apparatus has been adapted to be used, in some embodiments, with a tool assembly  160  disposed inside a coiled tubing string  12  as set forth herein. Referring to  FIG. 11 , the wellbore  1  extends from the Earth&#39;s surface into a subsurface Earth formation  2 . The wellbore  1  is shown as deviated from vertical, wherein the curvature thereof shown in the  FIG. 11  has been exaggerated for the sake of clarity. It is contemplated that the present invention will have particular advantages for use in such deviated wellbores, however the deviation of the wellbore is not a limit on the scope of the invention. 
   At least the lower part of the wellbore  1  that is shown in  FIG. 11  may be formed by the operation of certain components coupled to the lower end of the tubing string  12 . The components coupled to the lower end of the tubing string  12  are collectively referred to as a “bottom hole assembly”  8 , which includes a drill bit  310 , a drill steering system  312  and a surveying system  315 . The bottom hole assembly  8  can include a passage  320  forming part of a passageway for the tool assembly  160 , which may be disposed between a first position  328  in the interior of the tubing string  12 , above the bottom hole assembly  8 , and a second position  330  inside the wellbore  1  below the tubing string  12 , below the bottom hole assembly  8  and below the drill bit  3   10 . 
   It should be clearly understood that when the lower part of the tool assembly  160  is disposed below the bottom of the bottom hole assembly  8 , the upper part of the tool assembly  160  can remain in the tubing string  12 , for example, hung in or even above the bottom hole assembly  8 . For purposes of defining this aspect of the present invention it is sufficient that the lower part of the tool assembly  160  reaches the second position  330  in the wellbore  1 . It should be noted that various types of sensors may be included in the tool assembly  160  that can be used to measure one or more parameters in the wellbore  1  as the tool assembly  160  is lowered from the surface to the first position  328 , with measurement data stored in an internal memory or storage device in the tool assembly  160  or transmitted to the surface, such as by mud pressure modulation telemetry or by electrical and/or optical cable. Examples of sensors are described above with reference to  FIG. 25 . If the tool assembly  160  is positioned or inserted in the coiled tubing string ( 12  in  FIG. 1 ) at the first position  328  when the bottom hole assembly  8  is at or near the surface, then the sensors (not shown separately in  FIG. 11 ) can also make measurements above the drill bit  310  in logging while drilling (“LWD”) fashion as the wellbore  1  is drilled, in addition to measuring as described below when the tool assembly  160  is in the second position  330  as the tubing string  12  and drill bit  310  are withdrawn from the wellbore  1 . 
   In this latter embodiment, with the tool assembly  160  at or near the first position  328 , the portion of the tubing string  12 , or segment ( 159  in  FIG. 10A ), adjacent to the tool assembly  160  can be composed of composite or other electrically non-conductive material to facilitate making measurements with sensors adversely affected by steel or other electrically conductive material. It is also possible that antenna coils (not shown) can be located in grooves cut into the outside of the segment ( 159  in  FIG. 10A ) of the tubing string  12  containing the tool assembly  160 , and such antenna coils (not shown) used to make induction resistivity measurements of the formations outside the wellbore  1 . Power to the antenna coils and signal received in the antenna coils can be communicated across the tubing wall using electrical feed-through bulkheads of types well known in the art. Such electrically non-conductive material, whether forming an entire segment of the tubing string  12  or whether in the form of “windows” in the tubing string  12 , may also provide a path for electromagnetic energy if such is used for telemetry of data from the tool assembly  160  to the Earth&#39;s surface, and/or telemetry from the Earth&#39;s surface to the tool assembly  160 . 
   In the description which follows, the terms upper and above are used to refer to a position or orientation relatively closer to the surface end of the tubing string  12 , and the terms lower and below for a position relatively closer to the end of the wellbore during operation. The term longitudinal will be used to refer to a direction or orientation substantially along the axis of the tubing string  12 . 
   The drill bit  310  can be provided with a releasably connected insert  335 , which will be described in more detail with reference to  FIG. 14 . The insert  335  forms a selectively removable closure element for the passageway  320 , when it is in its closing position, i.e. connected to the drill bit  310  as shown in the  FIG. 11 . 
     FIG. 11  further shows a transfer tool  338  which is arranged at the upper end of the tool assembly  160 , and which serves to deploy the tool assembly  160  from its insertion point at the juncture of the connectors ( 28 ,  30  in  FIG. 2 ) to the bottom hole assembly  8 , for example, by pumping. For example, a transfer tool such as disclosed in published British Patent Application No. GB 2357787A can be used for such purpose. 
   Referring to  FIG. 12 , the surveying system  315  of  FIG. 11  is shown in more detail. The surveying system of this embodiment can be a measurement/logging while drilling (“MWD/LWD”) system comprising a tubular sub or collar  351  and an elongated probe  355 . The upper end of the tubular sub  351  is connectable to the upper part of the tubing string  12  extending to the surface, and the lower end is connectable to the steering system  312 . The probe  355  contains surveying instrumentation, a gamma ray instrument  356 , an orientation tool  357  including e.g. an magnetometer and accelerometer for determining dip and azimuth of the wellbore, various logging sensors (such as electromagnetic, acoustic, or nuclear sensors), a battery pack  358 , and a mud pulser  359  for data communication with the Earth&#39;s surface. The collar  351  can also contain surveying instrumentation. An annular shoulder  365  is arranged on the inner circumference of the tubular sub  351 , on which the probe can be hung off. The outer surface of the probe is provided with notches on which keys  369  are arranged that co-operate with the annular shoulder  365 . The notches allow for fluid to flow through the MWD/LWD system, and also induce the mud flow to go through the pulser section  359 . The upper end of the probe  355  can include a connection means such as a fishing neck or a latch connector, which co-operates with a tool such as a wireline tool or a pumping tool that can be lowered from the Earth&#39;s surface and connected to the connection means. The probe  355  can thus be pulled or pumped upwardly so as to remove the probe  355  from the collar  351 . The MWD/LWD system has dimensions such that the interior of the collar  351  after removal of the probe  355  represents a passageway  320  of suitable size for passage of at least the lower part of the tool assembly  160 . 
   In other embodiments, a collar-based MWD/LWD system can be used, wherein all components are arranged around a central longitudinal passageway of required cross-section, and do not include the probe  355 . In particular, a mud pulser can be provided that comprises a ring-shaped rubber member around the passageway, which can be inflated such that the rubber member extends into the passageway thereby creating a mud pulse. Other types of pulsers include valves that when open divert some of the fluid flow inside the tubing string into the annular space between the wellbore and the tubing string, and thus do not obstruct the central passageway. Still other MWD/LWD systems include no pulser. Such systems may include electromagnetic or acoustic telemetry to communicate data to the Earth&#39;s surface, or may merely record data in a suitable storage device in the MWD/LWD system itself, for recovery when the MWD/LWD system is removed to the Earth&#39;s surface. 
   Referring to  FIG. 13 , an embodiment of the drill steering system  312  of  FIG. 11 , in the form of a mud motor  404  in combination with a bent housing  405  will now be explained. The bent housing  405  is shown with an exaggerated bend angle between the upper and lower ends for clarity of the illustration. Ordinarily, the bend angle is on the order of less than three degrees. The bent housing  405  has an interior comparable to ordinary positive displacement or turbine-type drilling motors. The upper end of the mud motor  404  can be directly or indirectly connected to the lower end of the surveying system  315 . 
   A mud motor converts hydraulic energy from fluid (drilling mud) pumped from the Earth&#39;s surface to rotational energy to drive the drill bit ( 310  in  FIG. 11 ). Such energy conversion enables bit rotation without the need for tubing string rotation, and thus is suitable for drilling using coiled tubing strings. The mud motor  404  schematically shown in  FIG. 13  is a so-called positive displacement motor (“PDM”), which operates on the Moineau principle. The Moineau principle provides that a helically-shaped rotor, shown at  406 , with one or more lobes will rotate when it is placed inside a helically shaped stator  408  having one more lobe than the rotor when fluid is moved through annulus between stator and rotor. 
   Rotation of the rotor  406  is transferred to a tubular bit shaft  410 , to the lower end  412  of which the drill bit ( 310  in  FIG. 11 ) can be connected. To transfer the rotation to the bit shaft  410 , the lower end of the rotor  406  is connected via connection means  415  to one end of a transfer shaft  418 . The transfer shaft  418  extends through the bent housing  405  and is on its other end connected to the bit shaft via connection means  420 . The transfer shaft  418  can be a flexible shaft made from a material such as titanium that is able to withstand the bending and torsional stresses. Alternatively, the connection means  415  and  420  can be arranged as universal joints, constant velocity joints or other flexible coupling. The bit shaft  410  is suspended in a bit shaft collar  423 , which is connected to or integrated with the stator  408 , through bearings  425 . A seal  427  is provided between bit shaft  410  and bit shaft collar  423 . 
   The mud motor steering system of this embodiment differs from known systems in that the connection means  420  is arranged to release the connection between the transfer shaft  418  and the bit shaft  410  when upward force is applied to the rotor  406 . For example, the connection means can be formed as co-operating splines on the lower end of the transfer tool and on the upper part of the bit shaft. A suitable latch mechanism that can be operated by longitudinal pulling/pushing is another option. In order to be able to apply upward force on the rotor  406 , the upper end of the rotor is arranged as a connection means  430  such as a fishing neck or a latch connector, which co-operates with a tool that can be lowered from surface, connected to the connection means, and pulled or pumped upwardly so as to release the connection at connection means  420 . 
   The upper end  432  of the bit shaft  410  is funnel-shaped so as to guide the lower end of the transfer tool  418  to the connection means  420  when the rotor  406  is lowered into the stator  408  again. Fluid passages  435  for drilling fluid can be provided through the wall of the bit shaft  410 , to allow circulation of drilling fluid during drilling operation, when the rotor  406  is connected to the bit shaft  410  through connection means  420 . 
   Suitably, there is also arranged a means (not shown) that locks the bit shaft  410  in the bit shaft collar  423  when the rotor  406  has been disconnected from the bit shaft  410 . It shall be clear that the minimum inner diameter of the stator  408  and the bit shaft  410  are dimensioned such that a sufficiently large longitudinal passageway for at least the lower part of the tool assembly  160  is provided, forming part of the passageway  320  of  FIG. 11 . 
   An alternative drilling steering system is generally known as rotary steerable system. A rotary steerable system generally consists of an outer tubular mandrel having the outer diameter of the tubing string. Through the interior of the mandrel runs a piece of drill pipe of smaller diameter. The drill string or bottom hole assembly above the rotary steering system is connected to the upper end of this inner drill pipe, and the drill bit is connected to the lower end of the drill pipe. The mandrel comprises means to exert lateral force on the inner drill pipe so as to deflect the drill direction as desired. In order to be used with the present invention, the inner drill pipe of the rotary steering system must allow passage of an auxiliary tool. See, for example, U.S. Pat. Nos. 6,892,830; 6,837,315; 6,595,303; 6,158,529; and 6,116,354 for various implementations of rotary steerable directional drilling instruments. 
   Referring to  FIG. 14 , a schematically a longitudinal cross-section of an embodiment of the rotary drill bit  310  of  FIG. 11  is shown. The drill bit  310  is shown in the wellbore  1 , and is attached in this embodiment to the lower end of the bit shaft  410  of  FIG. 13 . The bit body  206  of the drill bit  410  has a central longitudinal passage  20  for an auxiliary tool from the interior  207  of the tubing string  12  to the wellbore  1  exterior of the drill bit  310 , as will be explained in more detail below. Bit nozzles are arranged in the bit body  206 . Only one nozzle with insert  209  is shown for the sake of clarity. The nozzle  209  is connected to the passageway  20  via the nozzle channel  209   a.    
   The drill bit  310  is further provided with a removable closure element  435 , which is shown in  FIG. 14  in its closing position with respect to the passageway  420 . The closure element  435  of this example includes a central insert section  212  and a latching section  214 . The insert section  212  is provided with cutting elements  216  at its front end, wherein the cutting elements are arranged so as to form, in the closing position, a joint bit face together with the cutters  218  at the front end of the bit body  206 . The insert section can also be provided with nozzles (not shown). Further, the insert section and the cooperating surface of the bit body  206  are shaped suitably so as to allow transmission of drilling torque from the bit shaft ( 410  in  FIG. 13 ) and bit body  206  to the insert section  212 . 
   The latching section  214 , which is fixedly attached to the rear end of the insert section  212 , has substantially cylindrical shape and extends into a central longitudinal bore  220  in the bit body  206  with narrow clearance. The bore  220  forms part of the passage  20 , it also provides fluid communication to nozzles in the insert section  212 . 
   The closure element  435  is removably attached to the bit body  206  by the latching section  214 . The latching section  214  of the closure element  435  comprises a substantially cylindrical outer sleeve  223  which extends with narrow clearance along the bore  220 . A sealing ring  224  is arranged in a groove around the circumference of the outer sleeve  223 , to prevent fluid communication along the outer surface of the latching section  214 . Connected to the lower end of the sleeve  223  is the insert section  212 . The latching section  214  further comprises an inner sleeve  225 , which slidingly fits into the outer sleeve  223 . The inner sleeve  225  is biased with its upper end  226  against an inward shoulder  228  formed by an inward rim  229  near the upper end of the sleeve  223 . The biasing force is exerted by a partly compressed helical spring  230 , which pushes the inner sleeve  225  away from the insert section  212 . At its lower end the inner sleeve  225  is provided with an annular recess  232  which is arranged to embrace the upper part of spring  230 . 
   The outer sleeve  223  is provided with recesses  234  wherein locking balls  235  are arranged. A locking ball  235  has a larger diameter than the thickness of the wall of the sleeve  223 , and each recess  234  is arranged to hold the respective ball  235  loosely so that it can move a limited distance radially in and out of the sleeve  223 . Two locking balls  235  are shown in the drawing, however, more locking balls can be used in other implementations. 
   In the closed position as shown in  FIG. 14  the locking balls  235  are pushed radially outwardly by the inner sleeve  225 , and register with the annular recess  236  arranged in the bit body  206  around the bore  220 . In this way the closure element  435  is locked to the drilling bit  410 . The inner sleeve  225  is further provided with an annular recess  237 , which is, in the closing position, longitudinally displaced with respect to the recess  236  in the direction of the bit shaft  410 . 
   The inward rim  229  is arranged to cooperate with a connection means  239  at the lower end of an opening tool  240 . The connection means  239  is provided with a number of legs  250  extending longitudinally downwardly from the circumference of the opening tool  240 . For the sake of clarity only two legs  250  are shown, but it will be clear that more legs can be arranged. Each leg  250  at its lower end is provided with a dog  251 , such that the outer diameter defined by the dogs  251  at position  252  exceeds the outer diameter defined by the legs  250  at position  254 , and also exceeds the inner diameter of the rim  229 . Further, the inner diameter of the rim  229  is preferably larger or about equal to the outer diameter defined by the legs  250  at position  254 , and the inner diameter of the outer sleeve  223  is smaller or approximately equal to the outer diameter defined by the dogs  251  at position  252 . Further, the legs  250  are arranged so that they are inwardly elastically deformable. The outer, lower edges  256  of the dogs  251  and the upper inner circumference  257  of the rim  229  are beveled. 
   The outer diameter of the opening tool  240  is significantly smaller than the diameter of the bore  220 . 
   Operation of the embodiment of  FIGS. 11-14  will now be described. The tubing string  12  can be used for progressing the wellbore  1  into the formation  2 , when the MWD/LWD probe  355  hangs in the collar  351  as shown in  FIG. 12 , when the rotor  406  is arranged in the stator  408  of the mud motor  404  as shown in  FIG. 13 , and when the insert  435  is latched to the bit body  206  as shown in  FIG. 14 . The tool assembly  160  would normally be stored at surface. The tubing string  12  can thus be used to drill the wellbore  1  into a desired subsurface position. The probe  355 , the rotor  406  and the insert  435  together form a closure element for the passageway  20 . 
   In the course of the drilling operation a situation can be encountered, which requires the operation of the tool assembly  160  in the wellbore  1  ahead of the drill bit  310 . This will be referred to as a tool operating condition. Examples are the occurrence of mud losses which require the injection of fluids such as lost circulation material or cement, performing a cleaning operation in the open wellbore, the desire to perform a special logging, measurement, fluid sampling or coring operation, the desire to drill a pilot hole. 
   Drilling is stopped then the tubing string  12  is pulled up a certain distance to create sufficient space for at least part of the tool assembly ( 160  in  FIG. 10 ) at position  430 , and the passageway is opened. To open the passageway in the present embodiment the MWD/LWD probe  355  and the rotor  406  can be retrieved to surface, such as by using a fishing tool with a connector means at its lower end that can be pumped down or upwardly through the drill string and can also be pulled up again by wireline. Retrieving of the MWD/LWD probe and the rotor can be done in consecutive steps. The lower end of the probe can also be arranged so that it can be connected to the connection means  430  at the upper end of the rotor  406 , so both can be retrieved at the same time. It will be appreciated by those skilled in the art that the foregoing operation may be performed by suitable location of connectors ( 28 ,  30  in  FIG. 1 ) in the tubing string  12 , such as explained above with reference to  FIG. 10 . When a set of connectors ( 28 ,  20  in  FIG. 10 ) is positioned suitably above the top of the wellbore, the connectors are disconnected, and a slickline (not shown) or similar device with an appropriate retrieval latch may be lowered into the interior of the tubing string  12  to retrieve the probe  355  and rotor  406 . After the probe  355  and rotor  406  are retrieved from the bottom hole assembly  8 , the tool assembly  160  may be inserted into the tubing string  12 . In embodiments of a survey system that do not include the probe ( 355  in  FIG. 11 ), it is not necessary to use slickline or the like for such purpose. 
   The opening tool  240  can then be deployed, through the interior of the tubing string  12 , so as to outwardly remove the closure element  435  from bit body  206 . The opening tool  240  is affixed to the lower end of the tool assembly  160 . The tool assembly  160  can be deployed from surface by pumping through the interior of the tubing string  12 , with the transfer tool  338  connected to the upper end of the tool assembly  160  (the tool can be logging, as described above, as it is lowered to contact the BHA). The tool assembly  160  passes though the tubing string  12  and the passageway  320  of the bottom hole assembly  8 , i.e. consecutively through the MWD collar  351  and the stator  408  of the mud motor, until it reaches the upper end of the drill bit  310 , so that the connection means  239  engages the upper end of the latching section  214  of the closure element  435 . The dogs  251  slide into the upper rim  229  of the outer sleeve  223 . The legs  250  are deformed inwardly so that the dogs  251  can slide fully into the upper rim  229  until they engage the upper end  226  of the inner sleeve  225 . By further pushing down, the inner sleeve  225  will be forced to slide down inside the outer sleeve  223 , further compressing the spring  230 . When the space between the upper end  226  of the inner sleeve  225  and the shoulder  228  has become large enough to accommodate the length of the dogs  251 , the legs  250  snap outwardly, thereby latching the opening tool  240  to the closure element  435 . 
   At approximately the same relative position between inner and outer sleeves, where the legs snap outwardly, the recesses  237  register with the balls  235 , thereby unlatching the closure element  435  from the bit body  206 . At further pushing down of the opening tool  240  the closure element  435  is integrally pushed out of the bore  220 . When the closure element  435  has been fully pushed out of the bore  220 , the passageway  320  is opened. 
   By moving the opening tool  240  further, the lower part of the tool assembly  160  at the upper end of the opening tool  240  enters the open wellbore  1  outside of the drill bit  310 , and it can be operated there. In this embodiment the tool assembly  160  is long enough so that it extends through the entire bottom hole assembly  8  and remains connected to the transfer tool  338  above the bottom hole assembly  8 . This allows straightforward retrieval of the tool assembly  160  to the surface, by slickline, wireline or reverse pumping. The wellbore  1  below the drill bit  310  may be surveyed by moving the entire tubing string  12  along the wellbore by reeling the reel ( 14  in  FIG. 1 ). 
     FIG. 15  shows the lower end of the drill bit  310  in the situation that a logging tool  260 , of which the lower part  261  has been passed through the passageway. The closure element  435  has been outwardly removed from the closing position by the opening tool  240  disposed at the lower end of the logging tool  260 . 
   A number of sensors and/or electrodes of the logging tool are shown at  266 . They can be battery-powered, or can be powered by a turbine or through electrical power transmitted along a wireline extending to surface. Data can be stored in the logging tool  260  or transmitted to surface. The logging tool  260  further comprises a landing member (not shown) having a landing surface, which cooperates with a landing seat of the bottom hole assembly  8 . 
   In one example, the drill bit  310  can for example have an outer diameter of 21.6 cm (8.5 inch), with a passageway of 6.4 cm (2.5 inch). The lower part  261  of the logging tool, which is the part that has passed out of the drill string onto the open wellbore, is in this case substantially cylindrical and has a relatively uniform outer diameter of 5 cm (2 inch). In one embodiment, the portion of the drill bit lowered beneath the tool assembly  160  can be used to continue to drill a smaller diameter bore hole for some distance below the bottom of the existing wellbore, with the sensors  266  in tool  260  continuing to measure and store and/or transmit measurement data as the smaller diameter borehole is being drilled. Drilling power may be provided by an electrical connection (not described) to the surface and a downhole electric motor, or by an additional mud motor (not shown). When the smaller borehole is drilled to the depth desired, the same sensors in the tool assembly  160  can measure, store and/or transmit data as the tubing string  12  is inserted into and/or withdrawn from the wellbore. 
   After the tool assembly  160  has been operated in the wellbore at  430 , it can be retrieved into the tubing string  12  by pulling up the transfer tool  338 . The closure insert  435  will then reconnect to the bit body  206 . The opening tool  240  will disconnect from the insert  435 , and the tool assembly  160  can be fully retrieved to the surface. Rotor  406  and MWD/LWD probe  355  can be lowered into the mud motor and MWD/LWD stator  408 , respectively, so that the closure element is complete again, and drilling can be resumed. If a following tool operation condition occurs, the whole cycle can be repeated, wherein in particular a different tool assembly can be used. The flexibility gained in this way during a directional drilling operation is a particular advantage of the present embodiment. 
   An alternative design to the removable center portion of the drill bit as explained above with reference to  FIGS. 11 through 15  is described in U.S. Patent Application Publication No. 2005/0029017, by Berkheimer et al., wherein the entire drill bit and/or entire bottom hole assembly is released and lowered below the tool assembly. 
   Yet another alternative embodiment is disclosed in U.S. Patent Application Publication No. 2006/0118298 filed by Millar et al. incorporated herein by reference, which discloses a tubing string assembly comprising a tubular first tubing string part with a passageway, and a second tubing string part co-operating with the first tubing string part. The assembly includes a releasable tubing string interconnecting means for selectively interconnecting the first and second tubing string parts. An auxiliary tool is provided for manipulating the second tubing string part. The auxiliary tool can pass along the passageway in the first tubing string part to the second tubing string part. The assembly further includes a tool-connecting means for selectively connecting the auxiliary tool to the second tubing string part, and an operating means for operating the tubing string-interconnecting means. 
   Wardley, U.S. Pat. No. 6,443,247, discloses a casing drilling shoe adapted for attachment to a casing string. The shoe comprises an outer drilling section constructed of a relatively hard material and an inner section made from a readily drillable material. The shoe includes means for controllably displacing the outer drilling section to enable the shoe to be drilled through using a standard drill bit and subsequently penetrated by a reduced diameter casing string or liner. Optionally, the outer section may be made of steel and the inner section may be made of aluminum. In some embodiments of a system according to the invention, the drill bit ( 310  in  FIG. 11 ) may be substituted by a drilling shoe as disclosed in the Wardley patent. Such a drilling shoe in the invention may be rotated by an annular drilling motor, as will be explained in more detail below with reference to  FIG. 17 . Such combination may be in substitution for all the components shown in  FIGS. 11-15  between the lower end of the tubing string  12  and the drill bit  310 . In using components such as shown in the Wardley patent with coiled tubing according to the invention, the wellbore is drilled to a selected depth. The tubing string may be withdrawn a selected distance out from the well. A tool assembly as explained above with reference to  FIG. 10  may then be inserted into the tubing string  12 . The tool assembly in such embodiments may have a device at the bottom end thereof that may open the outer section of the drilling shoe. The tool assembly may include a mill, bit or similar device on the bottom thereof that may be operated by an electric, hydraulic or drilling fluid-driven motor to rotate the mill or bit. Thus, the inner portion of the drilling shoe may be removed, and the tool assembly may be projected below the bottom of the tubing string into the wellbore below the bottom end of the tubing string. 
   Preferably, the outer section of the Wardley-type drilling shoe is provided with one or more blades, wherein the blades are moveable from a first or drilling position to a second or displaced position. Preferably, when the blades are in the first or drilling position they extend in a lateral or radial direction to such extent as to allow for drilling to be performed over the full face of the shoe. This enables the casing shoe to progress beyond the furthest point previously attained in a particular well. 
   The means for displacing the outer drilling section may comprise of a means for imparting a downward thrust on the inner section sufficient to cause the inner section to move in a down-hole direction relative to the outer drilling section. The means may include an obstructing member for obstructing the flow of drilling mud so as to enable increased pressure to be obtained above the inner section, the pressure being adapted to impart the downward thrust. Typically, the direction of displacement of the outer section has a radial component. 
   An alternative embodiment of a mud motor  500  in which all of the internal components of the motor may be moved out of the bottom of the coiled tubing string will now be explained with reference to  FIG. 16 . The motor includes a housing  500  that is slidably inserted into the bottom of the tubing string  12 . The bottom of the tubing string  12  may be particularly formed for the purpose of mounting the motor, or the motor may be mounted in a drill collar or similar device coupled to the lower end of the tubing string  12 . The interior of the tubing string or collar includes splines or Woodruff keys  506  that mate with corresponding slots in the exterior surface of the motor housing  500 . The keys or splines  506  rotationally fix the motor housing  500  with respect to the tubing string  12 , but enable the motor housing  500  to move axially within the tubing string  12  or collar. In the present embodiment, the motor housing  500  may be axially locked within the interior of the tubing string  12  or collar using a locking device substantially as explained with reference to  FIG. 14 , including, for example, an opening tool  240  coupled to the lower end of the tool assembly ( 160  in  FIG. 10 ) having dogs  250  or the like at the lowermost end. The dogs  250  interact with collets  229  on the upper end of the locking device to engage the release tool to the upper end of the motor. Movement of the opening tool  240  to engage the locking device enables release shaft  225  to move upward under bias from a spring  230 , such that locking balls  235  are move out of engagement with locking features in the wall of the tubing string or collar. Thus, continued movement of the tool assembly  160  downward will cause the motor housing  500  to be moved axially out of the bottom of the tubing string or collar. As the motor housing  500  is moved outward from the interior of the tubing string or collar, all the motor internal active components move therewith, including a rotor  502  having bit box  504  (and drill bit  310  coupled therein) coupled thereto, and the stator  508 . When the motor housing is thus moved out of the bottom of the tubing string or collar, a relatively large diameter through bore is created, through which the tool assembly ( 160  in  FIG. 10 ) may pass into the wellbore below the bottom of the tubing string. The embodiment shown in  FIG. 16  may be operated substantially as explained above with reference to  FIGS. 11-15 , the difference in the present embodiment being that it is not necessary to use slickline or other conveyance to remove the rotor  502  and other components (such as the MWD/LWD probe) prior to moving the tool assembly ( 160  in  FIG. 10 ) into the wellbore below the bottom of the tubing string or collar. 
   In other embodiments, the drill bit  310  may be substituted by a roller cone bit. One of the cones on the roller cone bit is substituted by a flapper or similar cover which can be opened to provide passage of the tool assembly  160  below the bit  310 , as described in Estes, U.S. Pat. No. 5,244,050. 
   Another embodiment of a mud motor having a through passage for the tool assembly ( 160  in  FIG. 10 ) is shown in  FIG. 17 . The embodiment shown in  FIG. 17  can be referred to as an annular motor, because the rotating components of the motor are disposed in an annular space  601  between an interior bore  606  and an outer surface of the motor housing  600 . The motor housing  600  is adapted to be coupled to the lower end of the tubing string  12 . Rotating components in the present embodiment can include a turbine  602 , or may include positive displacement (“PDM”) components, including but not limited to a Moineau-type rotor and stator combination. Rotational output of the turbine  602  or PDM can be coupled to a bit box  605  of configurations wellbore known in the art. In the present embodiment, the mud or other fluid pumped down the interior of the tubing string  12  has flow indicated by the arrows in  FIG. 17 . The center bore  606  in the operating configuration shown in  FIG. 17  includes a locking plug  604  that may be latched within the internal bore  606  using a latching mechanism similar to that shown in and explained with reference to  FIG. 14 . When the locking plug  604  is latched in place in the internal bore  606 , fluid flow is diverted to the annular space to drive the turbine  602  (or PDM). Fluid can return to the interior bore  606  through ports  608  at the lower end of the power section of the motor. 
   When the user desires to move the tool assembly ( 160  in  FIG. 10 ) outward through the bottom of the tubing string  12  into the open wellbore below, the tool assembly is moved downward until the opening tool ( 240  in  FIG. 14 ) couples with and releases the locking plug  604 . The locking plug  604  then moves downward with the tool assembly ( 160  in  FIG. 10 ). The locking plug  604  in the present embodiment includes releasing features  240 A that are substantially the same as the opening tool ( 240  in  FIG. 14 ). Thus, the locking plug  604  may be moved to release a center section of the drill bit substantially as explained with reference to  FIGS. 11 through 15 . When such center section is released, the tool assembly ( 160  in  FIG. 10 ) may be moved through the center opening in the drill bit and into the wellbore below the bottom of the tubing string  12 . Making formation evaluation or similar measurements using the various sensors on the tool assembly may be performed substantially as explained above with reference to  FIGS. 11 through 15 . Relatching both the center bit section and the locking plug  604  may be performed substantially as explained with reference to  FIGS. 14 and 15 . 
   Another embodiment is shown in  FIG. 18  in which wellbore logging sensors or similar apparatus remains inside the tubing string  12  during operation. A sub or collar  620  is coupled to the lower end of the tubing string  12 . The collar  12  may be made from composite, electrically non-conductive material such as glass fiber reinforced plastic, or may be made from high strength metal such as titanium. In the case of a metal collar, it may be useful for certain types of wellbore logging sensors to include radiation transparent windows  622  located to be aligned with the sensor (not shown) on the tool assembly  160 . In the present embodiment, the tool assembly  160  may include an alignment key  626  at its lowermost end, rather than the opening tool ( 240  in  FIG. 14 ) used in other embodiments. When the tool assembly  160  is inserted into and is moved through the tubing string  12 , the key  626  may seat in a keyway  624  in the collar  620 . The tool assembly  160  may also be inserted into the collar  620  prior to inserting the tubing string  12  into the wellbore. Wellbore logging operations may take place with the tool assembly  160  seated as shown in  FIG. 18  while the tubing string  12  is moved into and/or out of the wellbore, while drilling or otherwise. Information measured by the various sensors (not shown separately) on the tool assembly  160  may be recorded in a device in the tool assembly  160 , or may be communicated by one or more types of telemetry, including fluid pressure modulation, electromagnetic radiation, and/or communication along an electrical cable (not shown). In some implementations, an antenna in the form of a longitudinally wound coil  628  may be embedded in the wall or in a recess in the wall of the collar  620 . The antenna  628  may be used to communicate signals to and from the tool assembly  160  through a corresponding antenna  630 , or to communicate signals to and from a different location. 
   Another embodiment of a coiled tubing string that may be advantageously used with the annular motor explained with reference to  FIG. 17  will now be explained with reference to  FIGS. 19 and 20 . A coaxial, dual coiled tubing  12 A is shown being deployed into the wellbore from a reel  14  in  FIG. 19 . The coaxial, dual coiled tubing  12 A includes a substantially open, central passage or conduit  12 C. Coaxially disposed about the central conduit  12 C is an annulus  12 B. The annulus  12 B preferably can provide an hydraulic path from the Earth&#39;s surface to the bottom end of the dual coiled tubing  12 A, just as can the central conduit  12 C. As will be appreciated by those skilled in the art, the dual coiled tubing  12 A may include one or more connectors as explained above with reference to  FIGS. 1-10  for insertion of a tool assembly into the central conduit  12 C. Such tool assembly may be used according to any one or more of the previously described embodiments. 
   In another dual tubing embodiment, a turbine with a central passage to enable tools to pass through can be used in the lower portion of the tubing string  12 . Such a turbine is disclosed, for example, in U.S. Pat. No. 6,527,513 to Van Drentham-Susman et al. 
   A possible structure for a coaxial, dual coiled tubing  12 A is shown in cross section in  FIG. 20 . The tubing  12 A includes an outer tube  12 E and an inner tube  12 D. The inner tube  12 D defines therein in its interior the central conduit  12 C. The inner tube  12 D may be joined to the outer tube  12 D by circumferentially spaced apart supporting ribs  12 F. The supporting ribs  12 F transfer lateral and bending stresses between the inner tube  12 D and outer tube  12 E to maintain the shape and profile of the dual coiled tubing  12 A. Interior passages disposed between the ribs  12 F define the passages of the annulus  12 B. One or more of the passages may have therein disposed electrical lines or cables  13 E, or hydraulic lines  14 H. Such lines and cables may be used in some embodiments to supply power to operate the tool assembly ( 160  in  FIG. 10 ) in the wellbore, and/or to communicate signals from the tool assembly to the Earth&#39;s surface. The hydraulic lines could also be used to activate mechanical devices in the bottom hole assembly, including the latching and unlatching assemblies associated with moving and positioning the tool assembly  160  below the drill bit  310 , and if desired, retrieval of the tool assembly  160  and displaced drill bit  310  back into their ordinary drilling position. In some embodiments the tool assembly  160  can be stored in a side pocket while drilling the well and/or while extending the tubing string  12  into the wellbore. The hydraulic or electrical power could also be used in such circumstances to rotate or otherwise move the tool assembly  160  from the side-pocket position into the operating position below the bottom hole assembly as explained with reference to  FIG. 15 . It is contemplated that the dual coiled tubing shown in  FIG. 19  may be advantageously used with the annular motor shown in  FIG. 17 , however the annulus  12 B when used with electrical and/or hydraulic lines may also operate devices such as electric and/or hydraulic motors to operate the drill bit ( 310  in  FIG. 14 ). For embodiments of a dual coiled tubing made from steel or similar metal, it is contemplated that the dual coiled tubing  12 A may be made by continuous extrusion over an extruder die or similar manufacturing technique. It is also within the scope of this invention to place one or more sensors ( 15  in  FIG. 19 ) in selected positions along the tubing  12 A in the annulus  12 B. Such sensors may measure fluid pressure, temperature, signals from the tool assembly ( 160  in  FIG. 10 ) and any other parameters that would occur to those of ordinary skill in the art. Referring to  FIG. 1 , in which one of the wellbore tools disposed in the tubing string is a packer  18 , it is possible using such packer to seal the wellbore against the exterior of the tubing string  12  so that selected fluid flow paths with respect to the tubing  12 A can be isolated. In the example dual coiled tubing of  FIG. 19 , fluid can be pumped down the annulus  12 B and returned through the central conduit  12 C, or vice versa, while the annular space between the wellbore and the outer tube  12 E remains sealed against fluid flow by the packer ( 18  in  FIG. 1 ). Since the central conduit  12 C is open from the surface to the bottom hole assembly, there being no rotor/stator assembly or other device to impede or block the passageway, the tool assembly  160  can be positioned and lowered in the central conduit  12 C from the surface to the bottom hole assembly, and then further lowered into open borehole below the bottom hole assembly as described earlier with reference to  FIG. 15 . It may be possible, when the tool assembly  160  is lowered into such position, for an upper portion of tool assembly  160  to contain a transmitter (e.g., electromagnetic or acoustic) that can be aligned with a corresponding receiver disposed in the bottom hole assembly. Sensor signals from the various sensors generated in the tool assembly  160  can then be transferred from the tool assembly  160  to the receiver in the bottom hole assembly, and then further transmitted to the surface by any of mud pulse telemetry up the central conduit  12 C or annulus  12 B, acoustic telemetry up one of the coaxial coiled tubular strings, or along an electrical cable in the annulus  12 B. 
   Other embodiments of a non-coaxial dual coiled tubing that may be used in some embodiments may be similar to a composite coiled tubing such as disclosed in U.S. Pat. No. 5,285,008 to Sas-Jaworsky et al., or U.S. Pat. No. 6,663,453 to Quigley, incorporated herein by reference. 
     FIGS. 21 and 22  show embodiments of a dual coiled tubing as in the Sas-Jaworsky et al. patent. In  FIG. 21  an outer composite cylindrical member  718  is joined to a centrally located core member  712  by web members  716  to form two opposing cells  719 . The cells  719  are lined with an abrasive resistant, chemically resistant material  714  and the exterior of the composite tubular member is protected by an abrasion resistant cover  720 . At the center of core member  712  is an optional electrical conductor  715  having an insulating sheath  717  surrounding the conductor  715 . A braided or woven sheath  721  of electrically conductive material is shown formed about the insulating sheath  717 . The conductor  715  and sheath  721  form an electrical pair of conductors for operating tools, instruments, or equipment downhole, which tools are operably connected to the composite tubular member. 
   One advantage of the composite tubular member shown in  FIG. 21  is that the core  712  contains zero-degree oriented fibers which can assume large displacement away from the center of the cross-section of the composite tubular member during bending along with tube flattening to achieve a minimum energy state. Such deformation state has the beneficial result of lowering critical bending strains in the tube. The secondary reduction in strain will also occur in composite tubular members containing a larger number of cells, but is most pronounced for the two cell configuration. 
   A variation in design in the two cell configuration is shown in  FIG. 22  in which the zero degree oriented fiber  722  is widened to provide a plate-like core which extends out to the outer cylindrical member  724 . In effect, the central core member and the web members are combined to form a single web member of uniform cross-section extending through the axis of the composite tubular member. Two optional conductors  729  are shown spaced apart in the material  722  forming a plate-like core. If mud pulse telemetry or acoustic telemetry up the tubing string are used to send data from the tool assembly to the surface, it may be possible in some embodiments to place a special fluid either in the annulus of a concentric dual coiled tubing, or in one of the isolated dual tubes as shown in  FIGS. 21 and 22  to facilitate mud pulse or acoustic up-the-pipe telemetry. It is also possible that the side-by-side coiled tubings as described in  FIGS. 21 and 22  could be made from metallic material housed in a spoolable outer metallic or composite sheath. 
     FIG. 23  illustrates an embodiment of a side by side dual coiled tubing such as one shown in U.S. Pat. No. 6,663,453 to Quigley, wherein a containment layer  621  of a continuous buoyancy control system  620  is discretely attached to the tube  610  through the use of a plurality of straps  640 . In addition to the illustrated straps  640 , other types of fasteners may also be employed, including, but not limited to, banding, taping, clamping, discrete bonding, and other mechanical and/or chemical attachment mechanisms known in the art. The containment layer  621  of the continuous buoyancy control system  620  may also have a corrugated outer surface to inhibit the discrete fastener  640 , such as the bands or straps, from dislodging during the installation process. For example, the containment layer  621  may have a corrugated outer surface having a plurality of alternating peaks and valleys that are oriented circumferentially, for example, at approximately 90 degrees relative to the longitudinal axis of the containment layer  621 . The straps  640  may be positioned within the valleys of the corrugated surface to inhibit dislodging of the straps  640 . 
   Referring to  FIG. 24 , the containment layer  621  of the buoyancy control system  620  may also be continuously affixed to the tube  610  by an outer jacket  650  that encapsulates the tube  610  and the containment layer  621  of the buoyancy control system  20 . In the illustrated exemplary embodiment, the outer jacket  650  is a continuous tube having a generally oval cross-section that is sized and shaped to accommodate the tube  10  and the buoyancy control system  620 . Those skilled in the art will appreciate that other cross sections, including circular, may be used and that the outer jacket  650  may be made in discrete interconnected segments. The outer jacket  650  may extend along the entire length of the tube  610  or the buoyancy system  620  or may be disposed along discrete segments of the tube  610  and the buoyancy control system  620 . The outer jacket  650  may also be spoolable. 
   The outer jacket  650  may be a separately constructed tubular or other structure that is attached to the tube  610  and the system  620  during installation of the tube  610  and the system  620 . Alternatively, the outer jacket  650  may be attached during manufacturing of the tube  610  and/or the system  620 . The outer jacket  650  may be formed by continuous taping, discrete or continuous bonding, winding, extrusion, coating processes, and other known encapsulation techniques, including processes used to manufacture fiber-reinforced composites. The outer jacket  650  may be constructed from polymers, metals, composite materials, and materials generally used in the manufacture of polymer, metal, and composite tubing. Exemplary materials include thermoplastics, thermoset materials, fiber-reinforced polymers, PE, PET, urethanes, elastomers, nylon, polypropylene, and fiberglass 
   Fluid transport, and tool assembly and transport using tubing such as explained with reference to  FIGS. 21 ,  22 ,  23 , and  24  may be according to one or more of the previously described embodiments for a single coiled tubing or coaxial dual coiled tubing. 
   While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.