Abstract:
A tool positioning assembly for positioning downhole tools at desired locations within a wellbore. The current invention further provides methods for using a tool positioning assembly. The tool positioning assembly and methods for using the same reduce the number of downhole trips required to perform downhole operations.

Description:
BACKGROUND 
   The present invention relates to a downhole tool string assembly and method for positioning a downhole tool in a wellbore. More particularly, the present invention provides a tool positioning assembly capable of logging a well and determining locations within a wellbore as well as methods for using the same. 
   In the drilling and completion of oil and gas wells, a wellbore is drilled into the subterranean producing formation or zone of interest. Well completion may take one of several forms. One common completion method places and cements a casing in the wellbore. Following perforation of the casing, fluid is produced from the well through production tubing positioned within the casing. These subterranean strings of pipe are each comprised of a plurality of pipe sections joined together. The pipe joints, also often referred to as pipe collars or casing collars, can be detected because they produce an anomaly in a magnetic field as compared to other portions of the pipe string. 
   For the downhole tool to perform its planned function it must be positioned in the well at the proper depth. Following positioning, the downhole tool is activated by one of several methods, depending on the downhole tool. Methods of activation include but are not limited to tubing movement, tool movement, application of pressure, application of flow, dropping of balls on sleeves, pressure changes due to changes in flow rate, electronic means, or combinations of the above. 
   Knowledge of the precise location of casing collars and downhole formations is necessary when positioning downhole tools such as packers or perforating guns within the wellbore. Typically downhole tools are lowered into the well on a length of coiled tubing. The depth of a particular casing collar adjacent to or near the zone of interest to which the tool is positioned is generally determined on the basis of a previously recorded casing joint or collar profile for the well. That is, after open hole logs have been run in a drilled wellbore and one or more pipe strings have been cemented therein, an additional log is typically run within the pipe strings. The additional log is a depth reference log that establishes the position of casing collars to the previous open hole logs and respective zones of interest. This log typically becomes the working depth reference log for the well. Logging processes of this type are well known to those skilled in the art. 
   Given this readily available depth reference log, it would seem to be a straightforward task to lower a downhole tool to a desired location within any particular downhole zone of interest. In theory, a conventional surface based measuring device monitors the injection of the coiled tubing carrying the downhole tool and reports the arrival of the tool at the desired depth. However, regardless of the accuracy of the coiled tubing surface measuring device, true depth measurement is inherently flawed due to initial inaccuracies in the depth reference log, coiled tubing stretch, elongation from thermal effects, sinusoidal and helical buckling, and a variety of often unpredictable deformations in the length of coiled tubing suspended in the wellbore. 
   Attempts have been made to accurately control the depth of downhole tools connected to coiled tubing. One current method uses a production tubing end locator attached to coiled tubing. The production tubing end locator tool usually consists of collets or heavy bow springs that spring outwardly when the tool is lowered beyond the end of the production tubing string. Raising the coiled tubing pulls the tool back into the production tubing string thereby generating a drag force detectable by a weight indicator at the surface. 
   The use of such production tubing string end locator tools involves a number of problems. The most common problem is that not all wells include production tubing strings and only have casing or are produced open hole. Wells of this type lack a production tubing string on which the tool can catch when moved upward. Another problem associated with referencing the lower end of the production tubing string as a locator point results from the non-alignment of the tubing end with the zone of interest. Tubing section lengths are tallied as they are run in the well and mathematical or length measurement errors are common. Even when the tubing sections are measured and tallied accurately, the joint and tally log may not accurately locate the end of the tubing string with respect to the zone of interest. Yet another problem in the use of production tubing in locator tools is that a different sized tool must be used for different sizes of tubing. Further, in deviated or deep wells, the small weight increase as a result of the drag produced by the end locator tool is not enough to be noticeable at the surface. 
   While a variety of other types of casing collar locators have been developed including slick line indicators that produce a drag inside the tubing string, wireline indicators that send an electronic signal to the surface by way of electric cable and others, they either cannot be used as a component in a coiled tubing downhole tool system or have disadvantages when so used. The current invention overcomes the problems of the prior art by providing a novel tool positioning assembly and method for using the same. The novel downhole tool positioning assembly comprises a gamma ray detection assembly and optionally comprises a casing collar locator. Use of the novel tool positioning assembly reduces the necessity of multiple downhole trips to place other tools at desired downhole locations. 
   SUMMARY 
   The current invention provides a tool positioning assembly for positioning a downhole tool connected to a tool string. The tool positioning assembly comprises a housing having upper and lower ends adapted for connection to the tool string. The housing has a fluid passageway for providing fluid communication therethrough. A communication unit and a radiation detection unit for measuring radiation in the downhole environment and for generating a signal corresponding to the measured radiation are positioned within the housing. Also positioned within the housing is a control unit for receiving signal from the radiation detection unit and for controlling the communication unit. Finally, a power source suitable for providing power to the radiation detection unit, the control unit and the communication unit is also located within the housing. 
   In another embodiment, the current invention provides a tool positioning assembly for positioning a downhole tool connected to a tool string. Carried by coiled tubing, the tool positioning assembly comprises a housing having upper and lower ends adapted for connection to the tool string. The housing has a fluid passageway for providing fluid communication therethrough. Positioned within the housing are a casing collar locator, a radiation detection unit positioned for measuring radiation in the downhole environment and for generating a signal corresponding to the measured radiation, a communication unit and a control unit. The control unit receives signals from the casing collar locator and the radiation detection unit and directs the operation of the communication unit. Additionally, within the fluid passageway is a pressure isolation means for preventing fluid communication between the coiled tubing and a downhole tool incorporated into the tool string. Finally, a power source for providing power to the casing collar locator, the radiation detection unit, the control unit and the communication unit is positioned within the housing. 
   The current invention also provides a method for accurately positioning a downhole tool within a wellbore. According to the method of the current invention, a wellbore is drilled through at least one subterranean zone of interest and wellbore log prepared during or subsequent to drilling of the wellbore. Thereafter, a tool string is attached to tubing, the tool string comprises a tool positioning assembly and the downhole tool. The tubing and tool string are moved through the wellbore. As the tool string moves through the wellbore, the tool positioning assembly determines the concentration of radiation emissions within the wellbore. The location of the downhole tool is determined by correlating the relative strength of the radiation emissions to the wellbore log. The downhole tool is then positioned at the desired location by raising or lowering the tubing. 
   In yet another embodiment, the current invention provides a method for accurately positioning and activating a downhole tool within a wellbore. According to the method of the current invention, a wellbore is drilled through at least one subterranean zone of interest and wellbore log prepared during or subsequent to drilling of the wellbore. Thereafter, a tool string is attached to coiled tubing. The tool string comprises a tool positioning assembly and the downhole tool. The coiled tubing and tool string are injected into the wellbore to a depth below the zone of interest. The coiled tubing and tool string are then moved through the wellbore while determining the concentration of radiation emissions within the wellbore. Data corresponding to the relative strength of the radiation is transmitted to the surface and the location of the downhole tool is determined by correlating the relative strength of the radiation emissions to the wellbore log. The downhole tool is then positioned at the desired location by raising or lowering the coiled tubing. Once the tool is positioned at the desired location it is activated. 
   Still further, the current invention provides a method for accurately positioning and activating a downhole tool within a wellbore. According to the method of the current invention, a wellbore is drilled through at least one subterranean zone of interest and wellbore log prepared during or subsequent to drilling of the wellbore. Thereafter, a tool string is attached to tubing. The tool string comprises a tool positioning assembly and the downhole tool. A fluid pressure sensor is provided for detecting changes in fluid pressure within the tubing. The tubing and tool string are lowered into the wellbore. The tubing and tool string are then moved through the wellbore while determining the concentration of radiation emissions within the wellbore. As the tubing and tool string move through the wellbore, fluid flows through the tubing and tool string. Fluid pressure is continuously monitored by the fluid pressure sensor. Data corresponding to the relative strength of the radiation is transmitted to the fluid pressure sensor by varying the fluid pressure of the flowing fluid. The location of the downhole tool is determined by correlating the relative strength of the radiation emissions to the wellbore log. The downhole tool is then positioned at the desired location by raising or lowering the tubing. Following positioning at the desired location, the tool is activated. 
   Additionally, the current invention provides a method for accurately positioning and activating a downhole tool within a wellbore. According to the method of the current invention, a wellbore is drilled through at least one subterranean zone of interest and wellbore log prepared during or subsequent to drilling of the wellbore. Thereafter, a tool string is attached to coiled tubing. The tool string comprises a tool positioning assembly and the downhole tool. The tool positioning assembly comprises a housing having upper and lower ends adapted for connection to the tool string. The housing has a fluid passageway for providing fluid communication therethrough. Positioned within the housing is a casing collar locator, a radiation detection unit positioned for measuring radiation in the downhole environment and for generating a signal corresponding to the measured radiation, a mud pulser communication unit and a control unit. The control unit receives signals from the casing collar locator and the radiation detection unit and directs the operation of the communication unit. Additionally, the housing includes within the fluid passageway a pressure isolation means for preventing fluid communication between the coiled tubing and a downhole tool incorporated into the tool string. Additionally, the tool positioning assembly has a power source for providing power to the casing collar locator, the radiation detection unit, the control unit and the communication unit is positioned within the housing. The coiled tubing and tool string are lowered into the wellbore. The coiled tubing and tool string are then moved through the wellbore while determining the concentration of radiation emissions within the wellbore. Data corresponding to the relative strength of the radiation is transmitted to the surface. The location of the downhole tool is determined by correlating the relative strength of the radiation emissions to the wellbore log. The coiled tubing and tool string is then lowered to a point lower than the desired point for activating the downhole tool. The coiled tubing and tool string is then raised while continuing to monitor radiation emissions until the relative strength of radiation detected by the radiation detection unit reflects the desired depth for activating the tool. Upon reaching the desired depth, the tool is activated at the operator&#39;s convenience. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a schematic illustration of a cased well having a string of production tubing disposed therein and having a length of coiled tubing with the tool positioning assembly of the present invention connected thereto inserted therein by way of a coiled tubing injector and truck mounted reel. 
       FIGS. 2   a  and  2   b  are side cross-sectional views of the tool positioning assembly of the present invention. 
       FIG. 3   a  is a theoretical well log,  FIG. 3   b  is a theoretic correlation log and  FIG. 3   c  is a theoretical casing collar profile. 
   

   DETAILED DESCRIPTION 
   After a well has been drilled, it is often necessary to service the well whereby procedures are performed therein such as perforating, setting plugs, setting cement retainers, spotting permanent packers and the like. Coiled tubing is often used to carry out these procedures. Coiled tubing, relatively small flexible tubing, e.g., 1 to 3.5 inches in diameter, is normally stored on a reel when not in use. When used for performing well procedures, the tubing is passed through an injector mechanism and a tool string is connected to the end thereof. The tool string may comprise one or more tools joined together by any convenient means known to those skilled in the art. The injector mechanism pulls the tubing from the reel, straightens the tubing and injects it through a seal assembly at the wellhead known as a “stuffing box.” Typically, the injector mechanism injects thousands of feet of the coiled tubing with the tool string connected at the bottom end thereof into the casing string or the production tubing string of the well. A fluid, most often a liquid such as salt water, brine, mud or a hydrocarbon liquid, is circulated through the coiled tubing for operating the downhole tool(s) or for other purposes. The coiled tubing injector at the surface is used to raise and lower the coiled tubing and the tool string during the service procedure and to remove the coiled tubing and tool string as the tubing is rewound on the reel at the end of the procedure. 
   Because coiled tubing is most often used for these procedures, the following disclosure of the current invention will be described in conjunction with coiled tubing. However, the apparatus and methods of the current invention are equally suitable for use with other oil field tubing or pipe. 
   Referring now to  FIG. 1 , a well  10  is schematically illustrated along with a coiled tubing injector  12  and a truck mounted coiled tubing reel assembly  14 . The well  10  includes a wellbore  16  having a string of casing  18  cemented therein in the usual manner. A string of production tubing  20  is also installed in the well  10  within the casing string  18 . A length of coiled tubing  22  is inserted in the tubing string  20  having a tool positioning assembly  24  of the present invention connected at the bottom end thereof and a downhole tool  26  connected to the bottom end of the tool positioning assembly  24 . Tool positioning assembly  24  and downhole tool  26  comprises a tool string  27 . The arrangement of downhole tool  26  above or below tool positioning assembly  24  may vary from operation to operation as required for the unique characteristics of each well  10 . 
   For the purposes of this disclosure, the tool string  27  comprises at least one downhole tool  26  and tool positioning assembly  24 . Tool string  27  may comprise additional downhole tools as necessary for the particular operation. The actual arrangement of the downhole tools in tool string  27  is not critical to the current invention. As such, tool positioning assembly  24  may be connected directly to coiled tubing  22  or may be arranged as an intermediate or terminal part of tool string  27 . Further, other downhole tools  26  may be incorporated above or below tool positioning assembly  24 . 
   Coiled tubing  22  is inserted into the well  10  by way of a stuffing box  28  attached to the upper end of tubing string  20 . Stuffing box  28  functions to provide a seal between coiled tubing  22  and production tubing  20  whereby pressurized fluids within the well are prevented from escaping to the atmosphere. A circulating fluid removal conduit  30  having a shut-off valve  32  therein is sealingly connected to the top of the casing string  18 . The fluid circulated into the well  10  by way of the coiled tubing  22  is removed from the well by way of the conduit  30  and valve  32  from where it is routed to a pit, tank or other fluid accumulator (not shown). 
   The coiled tubing injector mechanism  12  is of a design known to those skilled in the art. Coiled tubing injector  12  straightens the coiled tubing and injects it into well  10  by way of stuffing box  28 . Coiled tubing injector  12  comprises a straightening mechanism  40  having a plurality of internal guide rollers  41  therein and a coiled tubing drive mechanism  42  for inserting the coiled tubing into the well, raising it or lowering it within the well and removing it from the well as it is rewound on a reel  50  of the assembly  14 . A depth measuring device  44  is connected to the coiled tubing drive mechanism  42 . Measuring device  44  continuously measures the length of coiled tubing  22  injected into the well  10  and provides that information by way of an electric transducer (not shown) and an electric cable  48  to an electronic data acquisition system  46 . 
   The truck mounted reel assembly  14  includes reel  50  for containing coils of the coiled tubing  22 . A guide wheel  52  for guiding the coiled tubing  22  on and off reel  50  is provided and a conduit assembly  54  is connected to the end of coiled tubing  22  on reel  50  by way of a swivel system (not shown). A shut-off valve  56  is disposed in conduit assembly  54  and conduit assembly  54  is connected to a fluid pump (not shown) which pumps the fluid to be circulated from a pit, tank or other fluid accumulator through conduit assembly  54  and into coiled tubing  22 . A fluid pressure sensor  58  or equivalent device is connected to conduit assembly  54  by way of a connection  60  attached thereto and to data acquisition system  46  by an electric cable  62 . As will be understood by those skilled in the art, data acquisition system  46  functions to continuously record the depth of coiled tubing  22  and tool positioning assembly  24  attached thereto in well  10  and the surface pressure of the fluid being pumped through coiled tubing  22  and tool positioning assembly  24 . 
   Referring now to  FIGS. 2   a  and  2   b , tool positioning assembly  24  of the present invention is illustrated in detail. Tool positioning assembly  24  includes an elongated cylindrical housing  70  having an internally threaded box connection  72  at the upper end for connecting the housing  70  to a complimentary connection of a coupling (not shown) attached to the end of coiled tubing  22  or another part of tool string  27 . An externally threaded box connection  74  is provided at the bottom end of housing  70  for connecting tool positioning assembly  24  to downhole tool  26  to be activated when properly positioned. Housing  70  is hollow and includes a fluid passageway  76  extending through its length. Passages  121  and  122  extend through housing  70  to provide fluid communication between passage  76  and the exterior of housing  70 . Mechanical unit  130  provides fluid communication between communication unit  120  and either annulus  23  or downhole tool  26  through passage  121 . If downhole tool  26  is sensitive to fluid pressure or fluid flow, then mechanical unit will direct fluid flow through passageway  121  to annulus  23  as shown in  FIG. 2   a . However, if downhole tool  26  is not sensitive to fluid flow or pressure then passageway  121  can direct fluid through downhole tool  26  as shown in  FIG. 2   b . Other arrangements of passageways  121  and  122  will be apparent to those skilled in the art. 
   The electronic components of tool positioning assembly  24  are disposed within housing  70  without blocking passageway  76 . For ease of construction, the electrical components of tool positioning assembly  24  are preferably prepared as separate units or sub-assemblies and fitted within housing  70 . In one embodiment, tool positioning assembly  24  comprises a power unit  80 , a casing collar locator unit  90 , a radiation detector unit  100 , a control unit  110 , a communication unit  120  and a mechanical unit  130 . Preferably, these units have a generally annular configuration thereby leaving passageway  76  unobstructed. 
   In general each unit has sufficient area to house the necessary electrical components for the given purpose of the unit. In unit  80 , annular space  85  will house a power source  86  such as a generator (not shown) or conventional batteries  86 . Power source  86  may be any conventional device, known to those skilled in the art, capable of generating sufficient electricity to power the other sub-assemblies. Power source  86  is connected by conventional wires and contacts generally designated by the numeral  88  to each unit requiring power. 
   While power unit  80 , casing collar locator unit  90 , radiation detector unit  100 , control unit  110 , communication unit  120  and mechanical unit  130  have been described as individual units positioned within housing  70 , each unit can be in the form of a sub-assembly which may be joined one to another in order to form downhole tool positioning assembly  24  and housing  70 . In this embodiment, the sub-assemblies have an annular configuration with each sub-assembly having an opening  76  which forms fluid passageway  76  when the sub-assemblies are joined together as tool positioning assembly  24 . Additionally, the current invention contemplates the combination of separate units. For example, control unit  110  and power unit may optionally be combined together as a single unit or sub-assembly prior to incorporation in downhole tool positioning assembly  24 . 
   As will be described in greater detail below, casing collar locator unit  90  and radiation detector unit  100  transmit data to control unit  110 . Subsequently, control unit  110  generates a signal directing the communication unit  120  to alter fluid pressure within coiled tubing  22 . Accordingly, control unit  110  houses electric circuit boards and other components  116 . The electric circuit boards and other components  116  may include central processors and other similar computer equipment capable of receiving and interpreting data as known to those skilled in the art. Components  116  are electrically connected to each unit by conventional wires and contacts  88 . In one embodiment, control unit  110  is provided with sufficient memory to permit storage of data for a period of time. Thus, data stored in control unit  110  may be transmitted subsequent to the logging operations or the data may be downloaded at the surface following retrieval of tool positioning assembly  24 . 
   Communication unit  120  provides the means for transmitting a pressure pulse detectable by pressure sensor  58 . Communication unit  120  comprises passageway  76 , a preferably electromagnetic valve  124 , a fluid chamber  125 , a poppet valve  126 , having a pressure by-pass valve  128  and spring  129 , and passageways  121 ,  122  and  123 . U.S. Pat. No. 5,586,084, incorporated herein by reference describes a mud pulser which may be readily adapted for use within communication unit  120 . Alternative pressure pulse generation devices suitable for transmitting signals in the method and assembly of the current invention are well known to those skilled in the art. 
   Communication unit  120  generates pressure pulses by movement of electromagnetic valve  124 . When electromagnetic valve  124  is closed poppet valve  126  is in the open position and passageways  121  and  122  provide fluid communication between passageway  76  and the exterior of tool positioning assembly  24 . When electromagnetic valve  124  is in the open position, passageway  123  provides fluid communication between fluid chamber  125  and passageway  76  closing poppet valve  126 . Thus, opening of electromagnetic valve  124  will create a pressure pulse within coiled tubing  22 . Finally, when the electromagnet valve closes pressure by-pass valve  128  provides fluid communication between fluid chamber  125  and passageway  121  allowing poppet valve  126  to open. 
   Mechanical section  130  provides the means for joining other downhole tools to tool positioning assembly  24 . In one embodiment, the means for joining downhole tools to tool positioning assembly  24  is in the form of a threaded external box connection  74 . Additionally, during logging operations passageway  76  is preferably blocked by a rupture disk  134  preferably located within mechanical section  130 . Rupture disk  134  prevents communication of fluid pressure to downhole tool  26 . Thus, rupture disk  134  isolates other downhole tools from fluid pressure within passageway  76 . Use of rupture disks and other similar devices are well known to those skilled in the art as demonstrated by U.S. Pat. No. 6,305,467 incorporated herein by reference. 
   Casing collar locator unit  90 , houses an electromagnetic coil assembly  95 . As the coiled tubing  22  is raised or lowered in the well  10  and tool positioning assembly  24  passes through a casing collar  21  of the production tubing string  20 , the electromagnetic coil assembly  95  electromagnetically senses the magnetic anomaly of casing collar  21 . The electronic circuit boards and other components generate a momentary electric output signal which is received by control unit  110 . 
   In one embodiment, control unit  110  interprets the electric signal received from casing collar locator unit  90  and in real time directs communication unit  120  to alter fluid pressure by operation of electromagnetic valve  124  in a predetermined pattern. The opening of electromagnetic valve  124  permits fluid communication between fluid chamber  125  and passageway  76 . The fluid pressure within fluid chamber  125  moves poppet valve  126  upwards blocking at least the majority of fluid passing through passageway  122 . The blockage of fluid flowing through passageway  122  produces a pressure pulse within passageway  76  and coiled tubing  22 . The coordinated opening and closing of electromagnetic valve  124  produces a series of pressure pulses detectable by pressure sensor  58 . Data acquisition system  46  interprets the pressure pulses and provides the means for correlating the earlier well log to the data provided by tool positioning assembly  24  thereby providing the means for accurately positioning downhole tools. 
   Radiation detector unit  100  houses a conventional radiation detector  105  and wiring and contacts  88  necessary to join radiation detector unit to control unit  110  and power unit  80 . The preferred radiation detector is a gamma ray detector or a neutron detector. Most preferred is a gamma ray detector. Preferably, radiation detector  105  can be turned on and off in response to signals received from control unit  110 . Following activation, radiation detector  105  measures radiation in the borehole and transmits the resulting data to the control unit  110 . Control unit  110  in turn directs the communication unit  120  to generate detectible changes in fluid pressure in the manner described above. 
   Units  80 ,  90 ,  100 ,  110 ,  120  and  130  are assembled within housing  70  by conventional means known to those skilled in the art. Conventional electric wires and contacts  88  connect communication unit  120  and the previously described electronic components in the other sub-assemblies. 
   The methods of the current invention for accurately positioning and operating a downhole tool will be described with continued reference to the drawings. The methods of the current invention are applicable in both cased and uncased wells using or omitting production tubing. Conventional methods of drilling and completing the well are suitable for use in the current invention. The methods of the current invention use an initial well log generated during or after drilling wellbore  16 . An initial well log normally measures formation characteristics such as but not limited to resistivity, neutron radiation, acoustics and spontaneous potential as known to those skilled in the art. Although not a requirement, the initial well log preferably includes a gamma ray radiation log of the well.  FIG. 3   a  depicts a theoretical initial gamma ray well log and  FIG. 3   c  depicts a theoretical casing collar profile. As known to those skilled in the art, casing collar logs or profiles are normally created by wireline logging following the process of casing the wellbore. The profile represents the position of collars with reference to the gamma ray log from the original wellbore log. 
   Following completion of wellbore  16 , the coiled tubing apparatus described above is positioned at well  10 . A tool string  27  comprising tool positioning assembly  24  and downhole tool  26  is attached to coiled tubing  22  and injected downhole. As depicted in  FIG. 1 , tool positioning assembly  24  and coiled tubing  22  are injected downhole through stuffing box  28  and production tubing  20 . Normally, fluid will be flowed through coiled tubing  22  and tool positioning assembly  24  during the injection process. 
   In one embodiment, coiled tubing  22  and tool positioning assembly  24  are lowered to a point within wellbore  16  lower than the desired location for operating downhole tool  26 . In this embodiment, control unit  110  is preferably in a dormant state during the injection process. The period of dormancy can be controlled by any conventional means. Typically, control unit  110  will include either a timer (not shown) set for a period of time estimated to be greater than the time necessary for injecting coiled tubing  22 , a pressure sensor (not shown) set to activate control unit  110  upon reaching a predetermined pressure, a flow activation sensor or any other means suitable for activating control unit  110  known to those skilled in the art. Regardless of the activation means, control unit  110  preferably activates automatically and tool positioning assembly  24  is ready for use. 
   Following activation of control unit  110 , radiation detector  105 , casing collar locator  90  and communication sub-assemblies are brought on-line. With tool positioning assembly  24  ready to take downhole measurements, coiled tubing  22  is preferably moved upwards while radiation detector  105  and casing collar locator  90  log the well. However, certain conditions may necessitate lowering tool positioning assembly  24  while logging the well. Radiation detector  105  and casing collar locator  90  transmit logged data to control unit  110 , which in turn directs communication unit  120  to open and close valves  124  and  126 . The movement of valves  124  and  126  creates pressure changes within the fluid flowing through coiled tubing  22 . These pressure changes are sufficient to be detected by fluid pressure sensor  58 . Preferably, pressure sensor  58  is located at the surface; however, the current invention does not preclude the positioning of the pressure sensor  58  at other locations. 
   In one embodiment of the current invention, tool positioning assembly  24  will then be raised to a point above the desired location for activating downhole tool  26 . Subsequently, the method continues to log the well and compare the resulting data to the earlier log while lowering tool positioning assembly  24  to a point below the zone of interest. The desired location for activating downhole tool  26  is accurately determined by once again raising tool positioning assembly  24  until the transmitted data indicates positioning of tool positioning assembly  24  and downhole tool  26  at the desired location. Thereafter, downhole tool  26  is activated. 
   To accurately determine the location of tool positioning assembly  24  and downhole tool  26  within the zone of interest, the method of the current invention compares or correlates the data obtained by tool positioning assembly  24  to the initial wellbore log. As depicted in  FIG. 3   b , a gamma ray correlation log obtained during the method of the current invention typically has a lower magnitude than an initial gamma ray wellbore log. The lower magnitude results from the partial shielding provided by the casing  18 .  FIG. 3   b  represents a theoretical correlation log depicting both casing collar data and gamma ray data. 
   Preferably, the correlation log is prepared by comparing an initial gamma ray log to a correlation gamma ray log generated by tool positioning assembly  24 . However, the correlation gamma ray log generated by tool positioning assembly  24  can be compared to any prior wellbore log such as but not limited to neutron radiation logs, acoustic logs, spontaneous potential logs, resistivity logs and other formation characteristic logs that may be developed by those skilled in the art. In general, generation of a correlation log does not require direct comparison of peaks. Rather, the correlation log provides depth correlation by comparing differences in downhole formations. 
   In one embodiment, downhole tool  26  is activated by an increase in fluid pressure. Thus, when tool positioning assembly  24  carries a rupture disk  134 , the operator will increase fluid pressure within passageway  76  sufficiently to break rupture disk  134 . The resulting fluid pressure within tool  26  will then activate tool  26 . 
   In one embodiment, electric data acquisition system  46  constantly receives real time data from depth measuring device  44  and fluid pressure sensing device  58 . Electric data acquisition system  46  utilizes this data to generate a correlation well log. The correlation well log includes radiation emission data and optionally includes casing collar data. However, as noted above, an alternate preferred embodiment provides for the delayed transmission of data by storing the data in control unit  110  to be transmitted or downloaded at a later time. 
   In an alternative embodiment of the method of the current invention, the current invention begins logging the well immediately upon injection of coiled tubing  22  and tool positioning assembly  24  into well  10 . Data concerning casing collars and radiation emissions is transmitted to electric data acquisition system  46  in the manner described above and correlated to the earlier wellbore log. Coiled tubing  22  and tool positioning assembly  24 , which carries tool  26 , are injected to a position lower than the desired tool activation point. Subsequently with continued well logging, coiled tubing  22 , tool positioning assembly  24  and downhole tool  26  are raised until the correlated data indicates that tool positioning assembly  24  and downhole tool  26  are at the desired location. Thereafter, downhole tool  26  is activated in the manner described above. 
   Other embodiments of the current invention will be apparent to those skilled in the art from a consideration of this specification or practice of the invention disclosed herein. However, the foregoing specification is considered merely exemplary of the current invention with the true scope and spirit of the invention being indicated by the following claims.