Abstract:
Method and apparatus for drilling a well bore in a hydrocarbon formation using concentric coiled tubing drill string having an inner coiled tubing string and an outer coiled tubing string defining an annulus there between. A drilling means comprising a reciprocating air hammer and a drill bit, a positive displacement motor and a reverse circulating drill bit, or a reverse circulating mud motor and a rotary dill bit, is provided at the lower end of the concentric coiled tubing drill string. Drilling medium is delivered through the annulus or inner coiled tubing string for operating the drilling means to form a borehole. Exhaust drilling medium comprising drilling medium, drilling cuttings and hydrocarbons are removed from the well bore by extraction through the other of the annulus or inner coiled tubing string.

Description:
FIELD OF THE INVENTION  
         [0001]    The present invention relates generally to a drilling method and apparatus for exploration and production of oil, natural gas, coal bed methane, methane hydrates, and the like. More particularly, the present invention relates to a concentric coiled tubing drill string drilling method and apparatus useful for reverse circulation drilling.  
         BACKGROUND OF THE INVENTION  
         [0002]    Drilling for natural gas, oil, or coalbed methane is conducted in a number of different ways. In conventional overbalanced drilling, a weighted mud system is pumped through a length of jointed rotating pipe, or, in the case of coiled tubing, through a length of continuous coiled tubing, and positive displacement mud motor is used to drive a drill bit to drill a borehole. The drill cuttings and exhausted pumped fluids are returned up the annulus between the drill pipe or coiled tubing and the walls of the drilled formation. Damage to the formations, which can prohibit their ability to produce oil, natural gas, or coalbed methane, can occur by filtration of the weighted mud system into the formation due to the hydrostatic head of the fluid column exceeding the pressure of the formations being drilled. Damage may also occur from the continued contact of the drilled formation with drill cuttings that are returning to surface with the pumped fluid.  
           [0003]    Underbalanced drilling systems have been developed which use a mud or fluid system that is not weighted and under pumping conditions exhibit a hydrostatic head less than the formations being drilled. This is most often accomplished by pumping a commingled stream of liquid and gas as the drilling fluid. This allows the formations to flow into the well bore while drilling, thereby reducing the damage to the formation. Nevertheless, some damage may still occur due to the continued contact between the drill cuttings and exhausted pumped fluid that are returning to surface through the annulus between the drill string or coiled tubing and the formation.  
           [0004]    Air drilling using an air hammer or rotary drill bit can also cause formation damage when the air pressure used to operate the reciprocating air hammer or rotary drill bit exceeds formation pressure. As drill cuttings are returned to surface on the outside of the drill string using the exhausted air pressure, damage to the formation can also occur.  
           [0005]    Formation damage is becoming a serious problem for exploration and production of unconventional petroleum resources. For example, conventional natural gas resources are deposits with relatively high formation pressures. Unconventional natural gas formations such as gas in low permeability or “tight” reservoirs, coal bed methane, and shale gases have much lower pressures. Therefore, such formations would damage much easier when using conventional oil and gas drilling technology.  
           [0006]    The present invention reduces the amount of contact between the formation and drill cuttings which normally results when using air drilling, mud drilling, fluid drilling and underbalanced drilling by using a concentric coiled tubing string drilling system. Such a reduction in contact will result in a reduction in formation damage.  
         SUMMARY OF THE INVENTION  
         [0007]    The present invention allows for the drilling of hydrocarbon formations in a less damaging and safe manner. The invention works particularly well in under-pressured hydrocarbon formations where existing underbalanced technologies can damage the formation.  
           [0008]    The present invention uses a two-string or concentric coiled tubing drill string allowing for drilling fluid and drill cuttings to be removed through the concentric coiled tubing drill string, instead of through the annulus between the drill string and the formation.  
           [0009]    The use of coiled tubing instead of drill pipe provides the additional advantage of continuous circulation while drilling, thereby minimizing pressure fluctuations and reducing formation damage. When jointed rotary pipe is used, circulation must be stopped while making or breaking connections to trip in or out of the hole. Further, when using jointed pipe, at each connection, any gas phase in the drilling fluid tends to separate out of the fluid resulting in pressure fluctuations against the formation.  
           [0010]    The present invention allows for a well bore to be drilled, either from surface or from an existing casing set in the ground at some depth, with reverse circulation so as to avoid or minimize contact between drill cuttings and the formation that has been drilled. The well bore may be drilled overbalanced or underbalanced with drilling medium comprising drilling mud, drilling fluid, gaseous drilling fluid such as compressed air or a combination of drilling fluid and gas. In any of these cases, the drilling medium is reverse circulated up the concentric coiled tubing drill string with the drill cuttings such that drill cuttings are not in contact with the formation. Where required for safety purposes, an apparatus is included in or on the concentric coiled tubing string which is capable of closing off flow from the inner string, the annulus between the outer string and the inner string, or both to safeguard against uncontrolled flow from the formation to surface.  
           [0011]    The present invention has a number of advantages over conventional drilling technologies in addition to reducing drilling damage to the formation. The invention reduces the accumulation of drill cuttings at the bottom of the well bore; it allows for gas zones to be easily identified; and multi-zones of gas in shallow gas well bores can easily be identified without significant damage during drilling.  
           [0012]    In accordance with one aspect of the invention, a method for drilling a well bore in a hydrocarbon formation is provided herein, comprising the steps of;  
           [0013]    providing a concentric coiled tubing drill string having an inner coiled tubing string, said inner coiled tubing string having an inside wall and an outside wall and situated within an outer coiled tubing string having an inside wall and an outside wall, said outside wall of said inner coiled tubing string and said inside wall of said outer coiled tubing string defining an annulus between the coiled tubing strings;  
           [0014]    connecting a drilling means at the lower end of the concentric coiled tubing drill string; and  
           [0015]    delivering drilling medium through one of said annulus or inner coiled tubing drill string for operating the drilling means to form a borehole and removing exhaust drilling medium by extracting exhaust drilling medium through said other of said annulus or inner coiled tubing string.  
           [0016]    The coiled tubing strings may be constructed of steel, fiberglass, composite material, or other such material capable of withstanding the forces and pressures of the operation. The coiled tubing strings may be of consistent wall thickness or tapered.  
           [0017]    In one embodiment of the drilling method, the exhaust drilling medium is delivered through the annulus and removed through the inner coiled tubing string. The exhaust drilling medium comprises any combination of drill cuttings, drilling medium and hydrocarbons.  
           [0018]    In another embodiment, the flow paths may be reversed, such that the drilling medium is pumped down the inner coiled tubing string to drive the drilling means and exhaust drilling medium, comprising any combination of drilling medium, drill cuttings and hydrocarbons, is extracted through the annulus between the inner coiled tubing string and the outer coiled tubing string.  
           [0019]    The drilling medium can comprise a liquid drilling fluid such as, but not limited to, water, diesel, or drilling mud, or a combination of liquid drilling fluid and gas such as, but not limited to, air, nitrogen, carbon dioxide, and methane, or gas alone. The drilling medium is pumped down the annulus to the drilling means to drive the drilling means. Examples of suitable drilling means are a reverse-circulating mud motor with a rotary drill bit, or a mud motor with a reverse circulating drilling bit. When the drilling medium is a gas, a reverse circulating air hammer or a positive displacement air motor with a reverse circulating drill bit can be used.  
           [0020]    In a preferred embodiment, the drilling means further comprises a diverter means such as, but not limited to, a venturi or a fluid pumping means, which diverts or draws the exhaust drilling medium, the drill cuttings, and any hydrocarbons back into the inner coiled tubing string where they are flowed to surface. This diverter means may be an integral part of the drilling means or a separate apparatus.  
           [0021]    The method for drilling a well bore can further comprise the step of providing a downhole flow control means attached to the concentric coiled tubing drill string near the drilling means for preventing any flow of hydrocarbons to the surface from the inner coiled tubing string or the annulus or both when the need arises. The downhole flow control means is capable of shutting off flow from the well bore through the inside of the inner coiled tubing string, through the annulus between the inner coiled tubing string and the outer coiled tubing string, or through both.  
           [0022]    The downhole flow control means can operate in a number of different ways, including, but not limited to:  
           [0023]    1. providing an electrical cable which runs inside the inner coiled tubing string from surface to the end of the concentric string, such that the downhole flow control means is activated by a surface control means which transmits an electrical charge or signal to an actuator at or near the downhole flow control means;  
           [0024]    2. providing a plurality of small diameter capillary tubes which run inside the inner coiled tubing string from surface to the end of the concentric string, such that the downhole flow control means is activated by a surface control means which transmits hydraulic or pneumatic pressure to an actuator at or near the downhole flow control means;  
           [0025]    3. providing a plurality of fiber optic cables which run inside the inner coiled tubing string from surface to the end of the concentric string, such that the downhole flow control means is activated by a surface control means which transmits light pulses or signals to an actuator at or near the downhole flow control means; and  
           [0026]    4. providing a radio frequency transmitting device located at surface that actuates a radio frequency receiving actuator located at or near the downhole flow control means.  
           [0027]    In another preferred embodiment, the method for drilling a well bore can further comprise the step of providing a surface flow control means for preventing any flow of hydrocarbons from the space between the outside wall of the outer coiled tubing string and the walls of the formation or well bore. The surface flow control means may be in the form of annular bag blowout preventors, which seal around the outer coiled tubing string when operated under hydraulic pressure, or annular ram or closing devices, which seal around the outer coiled tubing string when operated under hydraulic pressure, or a shearing and sealing ram which cuts through both strings of coiled tubing and closes the well bore permanently. The specific design and configuration of these surface flow control means will be dependent on the pressure and content of the well bore fluid, as determined by local law and regulation.  
           [0028]    In another preferred embodiment, the method for drilling a well bore further comprises the step of reducing the surface pressure against which the inner coiled tubing string is required to flow by means of a surface pressure reducing means attached to the inner coiled tubing string. The surface pressure reducing means provides some assistance to the flow and may include, but not be limited to, a suction compressor capable of handling drilling mud, drilling fluids, drill cuttings and hydrocarbons installed on the inner coiled tubing string at surface.  
           [0029]    In another preferred embodiment, the method for drilling a well bore further comprises the step of directing the extracted exhaust drilling medium to a discharge location sufficiently remote from the well bore to provide for well site safety. This can be accomplished by means of a series of pipes, valves and rotating pressure joint combinations so as to provide for safety from combustion of any produced hydrocarbons. Any hydrocarbons present in the exhaust drilling medium can flow through a system of piping or conduit directly to atmosphere, or through a system of piping and/or valves to a pressure vessel, which directs flow from the well to a flare stack or riser or flare pit.  
           [0030]    The present invention further provides an apparatus for drilling a well bore in hydrocarbon formations, comprising:  
           [0031]    a concentric coiled tubing drill string having an inner coiled tubing string having an inside wall and an outside wall and an outer coiled tubing string having an inside wall and an outside wall, said outside wall of said inner coiled tubing string and said inside wall of said outer coiled tubing string defining an annulus between the coiled tubing strings;  
           [0032]    a drilling means at the lower end of said concentric coiled tubing drill string; and  
           [0033]    a drilling medium delivery means for delivering drilling medium through one of said annulus or inner coiled tubing string for operating the drilling means to form a borehole and for removing exhaust drilling medium through said other of said annulus or inner coiled tubing string.  
           [0034]    The drilling medium can be air, drilling mud, drilling fluids, gases or various combinations of each.  
           [0035]    In a preferred embodiment, the apparatus further comprises a downhole flow control means positioned near the drilling means for preventing flow of hydrocarbons from the inner coiled tubing string or the annulus or both to the surface of the well bore.  
           [0036]    In a further preferred embodiment, the apparatus further comprises a surface flow control means for preventing any flow of hydrocarbons from the space between the outside wall of the outer coiled tubing string and the walls of the well bore.  
           [0037]    In another preferred embodiment, the apparatus further comprises means for connecting the outer coiled tubing string and the inner coiled tubing string to the drilling means. The connecting means centers the inner coiled tubing string within the outer coiled tubing string, while still providing for isolation of flow paths between the two coiled tubing strings. In normal operation the connecting means would not allow for any movement of one coiled tubing string relative to the other, however may provide for axial movement or rotational movement of the inner coiled tubing string relative to the outer coiled tubing string in certain applications.  
           [0038]    In another preferred embodiment, the apparatus further comprises a disconnecting means located between the connecting means and the drilling means, to provide for a way of disconnecting the drilling means from the concentric coiled tubing drill string. The means of operation can include, but not be limited to, electric, hydraulic, or shearing tensile actions.  
           [0039]    In another preferred embodiment, the apparatus further comprises a rotation means attached to the drilling means when said drilling means comprising a reciprocating air hammer and a drilling bit. This is seen as a way of improving the cutting action of the drilling bit.  
           [0040]    In another preferred embodiment, the apparatus further comprises means for storing the concentric coiled tubing drill string such as a work reel. The storage means may be integral to the coiled tubing drilling apparatus or remote, said storage means being fitted with separate rotating joints dedicated to each of the inner coiled tubing string and annulus. These dedicated rotating joints allow for segregation of flow between the inner coiled tubing string and the annulus, while allowing rotation of the coiled tubing work reel and movement of the concentric coiled tubing string in and out of the well bore. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0041]    [0041]FIG. 1 is a vertical cross-section of a section of concentric coiled tubing drill string.  
         [0042]    [0042]FIG. 2 is a general view showing a partial cross-section of the apparatus and method of the present invention as it is located in a drilling operation.  
         [0043]    [0043]FIG. 3 is a schematic drawing of the operations used for the removal of exhaust drilling medium out of the well bore.  
         [0044]    [0044]FIG. 4 a  shows a vertical cross-section of a downhole flow control means in the open position.  
         [0045]    [0045]FIG. 4 b  shows a vertical cross-section of a downhole flow control means in the closed position.  
         [0046]    [0046]FIG. 5 shows a vertical cross-section of a concentric coiled tubing connector.  
         [0047]    [0047]FIG. 6 is a schematic drawing of a concentric coiled tubing bulkhead assembly. 
     
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0048]    [0048]FIG. 1 is a vertical cross-section of concentric coiled tubing drill string  03  useful for drilling a well bore in hydrocarbon formations according to the present invention. Concentric coiled tubing drill string  03  comprises an inner coiled tubing string  01  having an inside wall  70  and an outside wall  72  and an outer coiled tubing string  02  having an inside wall  74  and an outside wall  76 . The inner coiled tubing string  01  is inserted inside the outer coiled tubing string  02 . The outer coiled tubing string  02  typically has an outer diameter of 73.0 mm or 88.9 mm, and the inner coiled tubing string  01  typically has an outer diameter of 38.1 mm, 44.5 mm, or 50.8 mm. Other diameters of either string may be run as deemed necessary for the operation. Concentric coiled tubing drill string annulus  30  is formed between the outside wall  72  of the inner coiled tubing string  01  and the inside wall  74  of the outer coiled tubing string  02 .  
         [0049]    Concentric coiled tubing drill string  03  is connected to bottom hole assembly  22 , said bottom hole assembly  22  comprising a reverse-circulating drilling assembly  04  and a reverse-circulating motor head assembly  05 . Reverse circulating motor head assembly  05  comprises concentric coiled tubing connector  06  and, in preferred embodiments, further comprises a downhole blowout preventor or flow control means  07 , disconnecting means  08 , and rotating sub  09 . Reverse-circulating drilling assembly  04  comprises impact or drilling bit  78  and impact hammer  80 .  
         [0050]    Rotating sub  09  rotates the reverse-circulation drilling assembly  04  to ensure that drilling bit  78  doesn&#39;t strike at only one spot in the well bore. Disconnecting means  08  provides a means for disconnecting concentric coiled tubing drill string  03  from the reverse-circulation drilling assembly  04  should it get stuck in the well bore. Downhole flow control means  07  enables flow from the well bore to be shut off through either or both of the inner coiled tubing string  01  and the concentric coiled tubing drill string annulus  30  between the inner coiled tubing string  01  and the outer coiled tubing string  02 . Concentric coiled tubing connector  06  connects outer coiled tubing string  02  and inner coiled tubing string  01  to the bottom hole assembly  22 . It should be noted, however, that outer coiled tubing string  02  and inner coiled tubing string  01  could be directly connected to reverse-circulation drilling assembly  04 .  
         [0051]    Flow control means  07  operates by means of two small diameter capillary tubes  10  that are run inside inner coiled tubing string  01  and connect to closing device  07 . Hydraulic or pneumatic pressure is transmitted through capillary tubes  10  from surface. Capillary tubes  10  are typically stainless steel of 6.4 mm diameter, but may be of varying material and of smaller or larger diameter as required.  
         [0052]    Drilling medium  28  is pumped through concentric coiled tubing drill string annulus  30 , through the motor head assembly  05 , and into a flow path  36  in the reverse-circulating drilling assembly  04 , while maintaining isolation from the inside of the inner coiled tubing string  01 . The drilling fluid  28  powers the reverse-circulating drilling assembly  04 , which drills a hole in the casing  32 , cement  33 , and/or hydrocarbon formation  34  resulting in a plurality of drill cuttings  38 .  
         [0053]    Exhaust drilling medium  35  from the reverse-circulating drilling assembly  04  is, in whole or in part, drawn back up inside the reverse-circulating drilling assembly  04  through a flow path  37  which is isolated from the drilling fluid  28  and the flow path  36 . Along with exhaust drilling medium  35 , drill cuttings  38  and formation fluids  39  are also, in whole or in part, drawn back up inside the reverse-circulating drilling assembly  04  and into flow path  37 . Venturi  82  aids in accelerating exhaust drilling medium  35  to ensure that drill cuttings are removed from downhole. Shroud  84  is located between impact hammer  80  and inner wall  88  of well bore  32  in relatively air tight and frictional engagement with the inner wall  86 . Shroud  84  reduces exhaust drilling medium  36  and drill cuttings  38  from escaping up the well bore annulus  88  between the outside wall  76  of outer coiled tubing string  02  and the inside wall  86  of well bore  32  so that the exhaust drilling medium, drill cuttings  38 , and formation fluids  39  preferentially flow up the inner coiled tubing string  01 . Exhaust drilling medium  35 , drill cuttings  38 , and formation fluids  39  from flow path  37  are pushed to surface under formation pressure.  
         [0054]    In another embodiment of the present invention, drilling medium can be pumped down inner coiled tubing string  01  and exhaust drilling medium carried to the surface of the well bore through concentric coiled tubing drill string annulus  30 . Reverse circulation of the present invention can use as a drilling medium air, drilling muds or drilling fluids or a combination of drilling fluid and gases such as nitrogen and air.  
         [0055]    [0055]FIG. 2 shows a preferred embodiment of the present method and apparatus for safely drilling a natural gas well or any well containing hydrocarbons using concentric coiled tubing drilling. Concentric coiled tubing drill string  03  is run over a gooseneck or arch device  11  and stabbed into and through an injector device  12 . Arch device  11  serves to bend concentric coiled tubing string  03  into injector device  12 , which serves to push the concentric coiled tubing drill string into the well bore, or pull the concentric coiled tubing string  03  from the well bore as necessary to conduct the operation. Concentric coiled tubing drill string  03  is pushed or pulled through a stuffing box assembly  13  and into a lubricator assembly  14 . Stuffing box assembly  13  serves to contain well bore pressure and fluids, and lubricator assembly  14  allows for a length of coiled tubing or bottomhole assembly  22  to be lifted above the well bore and allowing the well bore to be closed off from pressure.  
         [0056]    As was also shown in FIG. 1, bottom hole assembly  22  is connected to the concentric coiled tubing drill string  03 . Typical steps would be for the motor head assembly  05  to be connected to the concentric coiled tubing drill string  03  and pulled up into the lubricator assembly  14 . Reverse-circulating drilling assembly  04  is connected to motor head assembly  05  and also pulled into lubricator assembly  14 . Lubricator assembly  14  is manipulated in an upright position directly above the wellhead  16  and surface blowout preventor  17  by means of crane  18  with a cable and hook assembly  19 . Lubricator assembly  14  is attached to surface blowout preventor  17  by a quick-connect union  20 . Lubricator assembly  14 , stuffing box assembly  13 , and surface blowout preventor  17  are pressure tested to ensure they are all capable of containing expected well bore pressures without leaks. Downhole flow control means  07  is also tested to ensure it is capable of closing from surface actuated controls (not shown) and containing well bore pressure without leaks.  
         [0057]    Surface blowout preventor  17  is used to prevent a sudden or uncontrolled flow of hydrocarbons from escaping from the well bore annulus  88  between the inner well bore wall  86  and the outside wall  76  of the outer coiled tubing string  02  during the drilling operation. An example of such a blowout preventor is Texas Oil Tools Model # EG72-T004. Surface blowout preventor  17  is not equipped to control hydrocarbons flowing up the inside of concentric coiled tubing drill string, however.  
         [0058]    [0058]FIG. 3 is a schematic drawing of the operations used for the removal of exhaust drilling medium out of the well bore. Suction compressor  41  or similar device may be placed downstream of the outlet rotating joint  40  to maintain sufficient fluid velocity inside the inner coiled tubing string  01  to keep all solids moving upwards and flowed through an outlet rotating joint  40 . This is especially important when there is insufficient formation pressure to move exhaust medium  35 , drill cuttings  38 , and formation fluids  39  up the inner space of the inner coiled tubing string  01 . Outlet rotating joint  40  allows exhaust medium  35 , drill cuttings  38 , and formation fluids  39  to be discharged from the inner space of inner coiled tubing string  01  while maintaining pressure control from the inner space, without leaks to atmosphere or to concentric coiled tubing drill string annulus  30  while moving the concentric coiled tubing drill string  03  into or out of the well bore.  
         [0059]    Upon completion of pressure testing, wellhead  16  is opened and concentric coiled tubing drill string  03  and bottom hole assembly  22  are pushed into the well bore by the injector device  12 . A hydraulic pump  23  may pump drilling mud or drilling fluid  24  from a storage tank  25  Into a flow line T-junction  26 . In the alternative, or in combination, air compressor or nitrogen source  21  may also pump air or nitrogen  27  into a flow line to T-junction  26 . Therefore, drilling medium  28  can consist of drilling mud or drilling fluid  24 , gas  27 , or a commingled stream of drilling fluid  24  and gas  27  as required for the operation.  
         [0060]    Drilling medium  28  is pumped into the inlet rotating joint  29  which directs drilling medium  28  into concentric coiled tubing drill string annulus  30  between inner coiled tubing string  01  and outer coiled tubing string  02 . Inlet rotating joint  29  allows drilling medium  28  to be pumped into concentric coiled tubing drill string annulus  30  while maintaining pressure control from concentric coiled tubing drill string annulus  30 , without leaks to atmosphere or to inner coiled tubing string  01 , while moving concentric coiled tubing drill string  03  into or out of the well bore.  
         [0061]    Exhaust drilling medium  35 , drill cuttings  38 , and formation fluids  39  flow from the outlet rotating joint  40  through a plurality of piping and valves  42  to a surface separation system  43 . Surface separation system  43  may comprise a length of straight piping terminating at an open tank or earthen pit, or may comprise a pressure vessel capable of separating and measuring liquid, gas, and solids. Exhaust medium  35 , drill cuttings  38 , and formation fluids  39 , including hydrocarbons, that are not drawn into the reverse-circulation drilling assembly may flow up the well bore annulus  88  between the outside wall  76  of outer coiled tubing string  02  and the inside wall  86  of well bore  32 . Materials flowing up the well bore annulus  88  will flow through wellhead  16  and surface blowout preventor  17  and be directed from the blowout preventor  17  to surface separation system  43 .  
         [0062]    [0062]FIG. 4 a  is a vertical cross-section of downhole flow control means  07  in open position and FIG. 4 b  is a vertical cross-section of downhole flow control means  07  in closed position. Downhole flow control means  07  may be required within motor head assembly  05  to enable flow from the well bore to be shut off through either or both of the inner coiled tubing string  01  or the concentric coiled tubing drill string annulus  30 . For effective well control, the closing device should be capable of being operated from surface by a means independent of the well bore conditions, or in response to an overpressure situation from the well bore.  
         [0063]    Referring first to FIG. 4 a,  the downhole flow control means  07  allows drilling medium  28  to flow through annular flow path  90 . Drilling medium from the annular flow path  36  is directed in first diffuser sub  92  that takes the annular flow path  36  and channels it into single monobore flow path  94 . Drilling medium  28  flows through single monobore flow path  94  and through a check valve means  96  which allows flow in the intended direction, but operates under a spring mechanism to stop flow from reversing direction and traveling back up the annular flow path  36  or the single monobore flow path  94 . Downstream of check valve means  96  single monobore flow path  94  is directed through second diffuser sub  98  which re-directs flow from single monobore flow path  94  back to annular flow path  36 . When operated in the open position, exhaust drilling medium  35 , drill cuttings  38  and formation fluid  39 , including hydrocarbons, flow up through inner coiled tubing flow path  37 . Inner coiled tubing flow path  37  passes through hydraulically operated ball valve  100  that allows full, unobstructed flow when operated in the open position.  
         [0064]    Referring now to FIG. 4 b,  downhole flow control means  07  is shown in the closed position. To provide well control from inner coiled tubing flow path  37 , hydraulic pressure is applied at pump  47  to one of capillary tubes  10 . This causes ball valve  100  to close thereby closing off inner coiled tubing flow path  37  and preventing uncontrolled flow of formation fluids or gas through the inner coiled tubing string  01 . In the event of an overpressure situation in single monobore flow path  94 , check valve  96  closes with the reversed flow and prevents reverse flow through single monobore flow path  94 . In this embodiment, well bore flow is thus prohibited from flowing up annular flow path  36  or single monobore flow path  94  in the event formation pressure exceeds pumping pressure, thereby providing well control in the annular flow path  36 .  
         [0065]    An optional feature of downhole flow control means  07  would allow communication between single monobore flow path  94  and inner coiled tubing flow path  37  when the downhole flow control means is operated in the closed position. This would allow continued circulation down annular flow path  36  and back up inner coiled tubing flow path  37  without being open to the well bore.  
         [0066]    [0066]FIG. 5 is a vertical cross-section of concentric coiled tubing connector  06 . Both outer coiled tubing string  02  and the inner coiled tubing string  01  are connected to bottom hole assembly by means of concentric coiled tubing connector  06 . First connector cap  49  is placed over outer coiled tubing string  02 . First external slip rings  50  are placed inside first connector cap  49 , and are compressed onto outer coiled tubing string  02  by first connector sub  51 , which is threaded into first connector cap  49 . Inner coiled tubing string  01  is extended through the bottom of first connector sub  51 , and second connector cap  52  is placed over inner coiled tubing string  01  and threaded into first connector sub  51 . Second external slip rings  53  are placed inside second connector cap  52 , and are compressed onto inner coiled tubing string  01  by second connector sub  54 , which is threaded into second connector cap  52 . First connector sub  51  is ported to allow flow through the sub body from concentric coiled tubing drill string annulus  30 .  
         [0067]    [0067]FIG. 6 is a schematic diagram of a coiled tubing bulkhead assembly. Drilling medium  28  is pumped into rotary joint  29  to first coiled tubing bulkhead  55 , which is connected to the concentric coiled tubing drill string  03  by way of outer coiled tubing string  02  and ultimately feeds concentric coiled tubing drill string annulus  30 . First coiled tubing bulkhead  55  is also connected to inner coiled tubing string  01  such that flow from the inner coiled tubing string  01  is isolated from concentric coiled tubing drill string annulus  30 . Inner coiled tubing string  01  is run through a first packoff device  56  which removes it from contact with concentric coiled tubing drill string annulus  30  and connects it to second coiled tubing bulkhead  57 . Flow from inner coiled tubing string  01  flows through second coiled tubing bulkhead  57 , through a series of valves, and ultimately to outlet rotary joint  40 , which permits flow from inner coiled tubing string  01  under pressure while the concentric coiled tubing drill string  03  is moved into or out of the well. Flow from inner coiled tubing string  01 , which comprises exhaust drilling medium  35 , drill cuttings  38  and formation fluid  39 , including hydrocarbons, is therefore allowed through outlet rotary joint  40  and allowed to discharge to the surface separation system.  
         [0068]    An additional feature of second coiled tubing bulkhead  57  is that it provides for the insertion of one or more smaller diameter tubes or devices, with pressure control, into the inner coiled tubing string  01  through second packoff  58 . In the preferred embodiment, second packoff  58  provides for two capillary tubes  10  to be run inside the inner coiled tubing string  01  for the operation and control of downhole flow control means  07 . The capillary tubes  10  are connected to a third rotating joint  59 , allowing pressure control of the capillary tubes  10  while rotating the work reel.  
         [0069]    While various embodiments in accordance with the present invention have been shown and described, it is understood that the same is not limited thereto, but is susceptible of numerous changes and modifications as known to those skilled in the art, and therefore the present invention is not to be limited to the details shown and described herein, but intend to cover all such changes and modifications as are encompassed by the scope of the appended claims.