Patent Publication Number: US-8522869-B2

Title: Optical coiled tubing log assembly

Description:
CROSS REFERENCE TO RELATED APPLICATION(S) 
     This Patent Document is a continuation-in-part claiming priority under 35 U.S.C. §120 to U.S. application Ser. No. 11/135,314 entitled System and Methods Using Fiber Optics in Coiled Tubing filed on May 23, 2005 now U.S. Pat. No. 7,617,873, incorporated herein by reference in its entirety and which in turn claims priority under 35 U.S.C. §119(e) to U.S. Provisional App. Ser. No. 60/575,327, also entitled System and Methods Using Fiber Optics in Coiled Tubing, filed on May 28, 2004, and also incorporated herein by reference in its entirety. 
    
    
     FIELD 
     Embodiments described relate to logging tools for use in establishing an overall profile of a well, such as hydrocarbon or other wells. In particular, techniques are described of employing such tools in conjunction with fiber optic communication so as to further real-time communications and follow on treatment applications. 
     BACKGROUND 
     Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. As a result, over the years, well architecture has become more sophisticated where appropriate in order to help enhance access to underground hydrocarbon reserves. For example, as opposed to vertical wells of limited depth, it is not uncommon to find hydrocarbon wells exceeding 30,000 feet in depth which are often fairly deviated with horizontal sections aimed at targeting particular underground reserves. 
     In recognition of the potentially enormous expense of well completion, added emphasis has been placed on well monitoring and maintenance. That is, placing added emphasis on increasing the life and productivity of a given well may help ensure that the well provides a healthy return on the significant investment involved in its completion. Thus, over the years, well diagnostics and treatment have become more sophisticated and critical facets of managing well operations. 
     In the case of non-vertical (i.e. ‘horizontal’) wells as noted above, the more sophisticated architecture may increase the likelihood of accessing underground hydrocarbons. However, the nature of such wells presents particular challenges in terms of well access and management. For example, during the life of a well, a variety of well access applications may be performed within the well with a host of different tools or measurement devices. However, providing downhole access to wells of such challenging architecture may require more than simply dropping a wireline into the well with the applicable tool located at the end thereof. Rather, coiled tubing is frequently employed to provide access to wells of more sophisticated architecture. 
     Coiled tubing operations are particularly adept at providing access to highly deviated or tortuous wells where gravity alone fails to provide access to all regions of the wells. During a coiled tubing operation, a spool of pipe (i.e., a coiled tubing) with a downhole tool at the end thereof is slowly straightened and forcibly pushed into the well. This may be achieved by running coiled tubing from the spool, at a truck or large skid, through a gooseneck guide arm and injector which are positioned over the well at the oilfield. In this manner, forces necessary to drive the coiled tubing through the deviated well may be employed, thereby advancing the tool through the well. 
     Well diagnostic tools and treatment tools may be advanced and delivered via coiled tubing as described above. Diagnostic tools, often referred to as logging tools, may be employed to analyze the condition of the well and its surroundings. Such logging tools may come in handy for building an overall profile of the well in terms of formation characteristics, well fluid and flow information, etc. In the case of production logging, such a profile may be particularly beneficial in the face of an unintended or undesired event. For example, unintended loss of production may occur over time due to scale buildup or other factors. In such circumstances, a logging tool may be employed to determine an overall production profile of the well. With an overall production profile available, the contribution of various well segments may be understood. Thus, as described below, corrective maintenance in the form of a treatment application may be performed at an underperforming well segment based on the results of the described logging application. For example, in the case of scale buildup as noted above, an acidizing treatment may subsequently be employed at the location of the underperforming segment. 
     Unfortunately, in circumstances where an accurate production profile is obtained via coiled tubing as described above, the entire coiled tubing must be removed before a treatment application may ensue. Once more, due to the challenging architecture of the well, the treatment application is again achieved via coiled tubing. Thus, a separate coiled tubing assembly must generally be available at the well site for delivery of a treatment tool (e.g. for an acidizing treatment at an underperforming well segment). In addition to added capital expense, this will ultimately cost a significant amount of time. That is, substantial time is lost in terms of withdrawal of the initial coiled tubing and rigging-up the subsequent coiled tubing for treatment, not to mention the time incurred in actually running the treatment application. All in all, several hours to days are often lost due to the duplicitous nature of such coiled tubing deployments. 
     The apparent redundancy in repeated coiled tubing deployments as described above, is due to the functional equipment requirements of conventional logging tools. For example, the logging tool is much more than a mere pressure or temperature sensor. Rather it is an electrically powered device that is equipped for significant data acquisition and communication with hardware at the surface of the oilfield. Therefore, the delivery of such tools includes the advancement of an electrical cable that powers the tool, such as a conventional wireline cable that also communicatively tethers the tool to hardware at the oilfield surface. 
     As a result of the presence of a cable through the coiled tubing as noted above, treatment applications through the coiled tubing are generally impractical. That is, the substantial diameter of the cable relative that of the coiled tubing occludes the coiled tubing so as to limit flow, ballistic actuation (e.g. ‘ball drop’), and other features often employed in the subsequent treatment application. For example, a standard cable may be up to about 0.6 inches or more in diameter while disposed in coiled tubing having an inner diameter of generally less than about 2 inches. Furthermore, even in the case of low flow acidizing as noted above, the treatment itself is likely to damage the polymeric nature of the cable&#39;s outer layers. As a result, future communications with the logging tool would be impaired until the time and expense of cable replacement and/or repair were incurred. Thus, as a practical matter, coiled tubing logging applications generally remain followed by separately deployed coiled tubing treatment applications where necessary. 
     SUMMARY 
     A logging assembly is provided for disposal in a well. The assembly includes coiled tubing deployable from an oilfield surface adjacent the well with a fiber optic line disposed therethrough. A logging tool is coupled to the fiber optic line and is configured to acquire well information. 
     An assembly is also provided that includes coiled tubing deployable from an oilfield surface adjacent the well. The assembly also includes an interventional treatment device coupled to the coiled tubing so as to allow performance of an interventional application relative to the well. Additionally, a logging tool is provided coupled to the coiled tubing. The logging tool is configured to acquire well information for establishing an overall profile of the well. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a side, partially-sectional, view of an embodiment of an optical coiled tubing log assembly. 
         FIG. 2A  is a cross-sectional view of the log assembly taken from  2 - 2  of  FIG. 1 . 
         FIG. 2B  is an alternate side cross sectional view of the log assembly of  FIG. 1 . 
         FIG. 3  is a partially sectional overview of a hydrocarbon well at an oilfield accommodating the assembly of  FIG. 1  and surface equipment therefor. 
         FIG. 4A  is a schematic representation of an embodiment of a surface opto-electric interface for the surface equipment of  FIG. 3 . 
         FIG. 4B  is a schematic representation of an embodiment of a downhole opto-electric interface for the log assembly of  FIG. 3 . 
         FIG. 5A  is a partially sectional side view of a production region of the well accommodating a logging tool of the assembly of  FIG. 3 . 
         FIG. 5B  is a partially sectional side view off the production region of  FIG. 5A  accommodating a treatment tool of the assembly of  FIG. 3 . 
         FIG. 6  is a flow-chart summarizing an embodiment of logging and treating a well with an optical coiled tubing log assembly. 
     
    
    
     DETAILED DESCRIPTION 
     Embodiments are described with reference to certain features and techniques of fiber optically enabled log assemblies that include coiled tubing for downhole delivery. As such, depicted embodiments focus on advantages such as well treatment capacity made available by the use of fiber optic communications with such coiled tubing log assemblies. Thus, embodiments are generally depicted with incorporated treatment tools. However, a variety of configurations may be employed with and without treatment tools. That is, an optically enabled coiled tubing log assembly may be employed apart from a follow-on treatment application. Regardless, embodiments described herein are employed that include a logging tool deliverable downhole via coiled tubing, while employing a fiber optic line for communications. Thus, at a minimum, enhanced high-speed communications may be made available via an overall lighter weight assembly. 
     Referring now to  FIG. 1 , an optical coiled tubing log assembly  100  is shown. The assembly  100  includes a logging tool  150  disposed at the end thereof and is configured for downhole advancement via coiled tubing  110 . However, as noted above, a fiber optic line  101  is provided so as to provide communicative capacity between the logging tool  150  and surface delivery equipment  325  (see  FIG. 3 ). Thus, a host of advantages are provided to the assembly  100 . These advantages may even include well treatment capacity. As described below, such treatment capacity is made practical by the substantial amount of available coiled tubing volume  275  through which fluid or other treatment elements may proceed (see  FIG. 2A ). For example, in the embodiment shown, a treatment device  125  is incorporated into the assembly  100 . In this embodiment, perforations  135  are provided through the device  125  such that an acidizing agent  500  may ultimately be delivered during a treatment application (see  FIG. 5 ). However, a host of alternate types of treatment applications may be employed through the assembly  100 . 
     Continuing with reference to  FIG. 1 , the logging tool  150  is configured to acquire a variety of logging data from a well  380  and surrounding formation layers  390 ,  395 , such as those of  FIG. 3 . The use of a fiber optic line  101  substantially reduces the overall weight of the assembly  100  as compared to a conventional cable communications, while also providing high-bandwidth for reliable high speed data transfer, in addition to occupying a relatively small cross-section or footspace within the coiled tubing  110 . More specifically, unlike a conventional cable, the fiber optic line  101  of the depicted assembly  100  may weigh substantially less than about ⅓ lb. per foot while also contributing substantially less than about 25% to the overall weight of the assembly  100 . Additionally, as noted below, the line  101  may be of no more than about 0.25 inches in diameter, preferably less than about 0.125 inches (i.e. substantially less than about 0.3 inches as would be expected for a conventional electrical cable). Thus, as detailed further, available coiled tubing volume  275  remains, for example, as a suitable channel for actuation of downhole treatment applications. 
     While being ideally suited for high speed communications, the use of fiber optic material for the line  101  also eliminates electrical conveyance, such as copper wiring. This allows for the weight of the line  101  to be substantially reduced as compared to a conventional cable. Therefore, powering of the logging tool  150 , treatment tool  125 , and any other downhole device may be achieved by a downhole power source (see the battery  490  of  FIG. 4B ). Along these lines, a downhole opto-electric interface  115  is provided such that electrical and light signals may be converted as necessary for communication between electrically powered tools  125 ,  150  and the fiber optic line  101 . 
     In the embodiment of  FIG. 1 , the logging tool  150  includes a host of well profile generating equipment or implements. This equipment may be configured for production logging directed at acquiring well fluids and formation measurements from which an overall production profile may be developed. However, in other embodiments, alternate types of logging may be sought. The noted equipment includes a sonde  160  equipped to acquire basic measurements such as pressure, temperature, casing collar location, and others. Density acquisition  170  and gas monitoring  180  devices are also provided. The tool  150  also terminates at a caliper and flow imaging tool  190  which, in addition to imaging, may be employed to acquire data relative to tool velocity, water, gas, flow and other well characteristics. As indicated, this information may be acquired at surface in a high speed manner, and, where appropriate, put to immediate real-time use (e.g. via a treatment application). 
     Referring now to  FIGS. 2A and 2B , cross-sectional views of the assembly  100  are shown. These views are of the coiled tubing  110  portion of the assembly  100  disposed within a well  380 . In particular, the relationship of the fiber optic line  101  relative the surrounding tubing  110  is visible. For example,  FIG. 2A  is a cross-sectional view taken from  2 - 2  of  FIG. 1 . In this view, the available coiled tubing volume  275 , un-occluded by the relatively small line  101  is quite apparent. As noted above, the line  101  may take up no more than about 0.25 inches in diameter at the most, whereas the inner diameter of the tubing  110  is substantially greater than about 1 inch, preferably over 2 inches. Thus, the available un-occluded volume  275  is sufficient for effective channeling of fluid or other treatment elements for a downhole treatment application. The application may even proceed without increase in friction losses. 
     The cross-sectional view of  FIG. 2A , also reveals internal features of the fiber optic line  101 . Namely, the line  101  may be made up of a core  200  of separate fibers  250 ,  255  surrounded by a protective casing  225 . The fibers  250 ,  255  may include a transmission fiber  250  to carry downhole transmissions of light from an uphole light source  440  located at surface (of an oilfield  300 ) (see  FIGS. 3 and 4A ). A return fiber  255  may also be included to carry uphole transmissions of light originating from a downhole light source  441  at a downhole opto-electric interface  115  (see  FIG. 4B ). 
     The casing  225  surrounding the core  200  of fibers  250 ,  255  may be of a metal based material such as stainless steel, an austenitic nickel-chromium-based superalloy, such as inconel, a transition metal nickel, or other appropriate temperature and/or corrosion resistant metal based material. For example, in other embodiments, acid resistant carbon or polymer-based coatings may be utilized. Corrosion resistance to acid and hydrogen sulfide, may be of particular benefit. Indeed, the line  101  may be well protected for use in a well environment and in light of any follow on treatment application, such as acidizing treatment channeled through the available volume  275  of the coiled tubing  110 . 
     In alternate embodiments, more than two fibers may be employed for transmitting of light-based data communications between the surface and downhole tools such as the logging tool  150  of  FIG. 1 . In fact, in one particular embodiment, a single fiber is employed for communicative transmissions in both uphole and downhole directions. For example, in such an embodiment, downhole transmissions may be of a given frequency that is different from that of uphole transmissions. In this manner, both uphole and downhole transmissions may take place over the same fiber and at the same time without conflict. 
     Referring now to  FIG. 3 , an overview of a hydrocarbon well  380  at an oilfield  300  is depicted. In the embodiment shown, the well  380  is defined by a casing  385 . However, embodiments of equipment, tools and techniques described herein may be employed in an un-cased or open-hole well. In the depiction of  FIG. 3 , the well  380  accommodates the optical coiled tubing log assembly  100  during a logging and/or treatment application. More specifically, in the embodiment shown, a production logging application may be run with the assembly  100  followed by a treatment application that employs the same assembly  100 . Indeed, depending on parameters of the operation, the production log and treatment application may both be run without any intervening removal of the assembly  100  from the downhole location as shown. 
     Continuing with reference to  FIG. 3 , the assembly  100  is positioned downhole and directed toward a previously fractured production region  375 . Thus, the logging tool  150  is employed for building a production profile of the well  380 . In the depiction of  FIG. 3 , debris  377  such as scale may be present at the production region  375 . Indeed, the presence of such debris  377  may be discovered and evaluated via the described production logging. Therefore, in one embodiment, as noted above, a follow-on treatment application may take place in real-time, via the treatment tool  125 . That is, the logging application may be completed, or even temporarily halted, and the treatment tool  125  positioned for a treatment application directed at the debris  377 . In this manner, the advancing assembly  100  is equipped for real-time adjustment to operational parameters based on the production log data that is being acquired. While the treatment described is acidizing (see  FIG. 5B ), other forms of cleanout may take place in a similar manner. Indeed, alternate treatment applications such as matrix stimulation, fracturing, zonal isolation, perforating, fishing, milling, and even the shifting of a casing sleeve, may take place through such an optical coiled tubing log assembly  100 . 
     Advancement of the assembly  100  as described above is directed via the coiled tubing  110 . Surface delivery equipment  325 , including a coiled tubing truck  335  with reel  310 , is positioned adjacent the well  380  at the oilfield  300 . The coiled tubing  110  may be pre-loaded with the fiber optic line  101  of  FIG. 1  by pumping a fluid into the coiled tubing  110  which in turn pulls the fiber optic line  101  relative to the coiled tubing  110  due to frictional forces. The terminal end of the line  101  may then be coupled to the interface  115  described below with appropriate electrically powered downhole tools  125 ,  150  attached. With the coiled tubing  110  run through a conventional gooseneck injector  355  supported by a rig  345  over the well  380 , the coiled tubing  110  and assembly  100  may then be advanced. That is, the coiled tubing  110  may be forced down through valving and pressure control equipment  365 , often referred to as a ‘Christmas tree’, and through the well  380  (e.g. allowing a production logging application to proceed). 
     The above manner of advancing the coiled tubing  110  and assembly  100 , and initiating a logging application, may be directed by way of a control unit  342 . In the embodiment shown, the control unit  342  is computerized equipment secured to the truck  335 . However, the unit  342  may be of a more mobile variety such as a laptop computer. Additionally, powered controlling of the application may be hydraulic, pneumatic and/or electrical. Regardless, the wireless nature of the direction allows the unit  342  to control the operation, even in circumstances where subsequent different application assemblies are to be deployed downhole. That is, the need for a subsequent mobilization of control equipment may be eliminated. 
     As detailed further below, the unit  342  wirelessly communicates with a transceiver hub  344  of the coiled tubing reel  310 . The receiver hub  344  is coupled to a surface opto-electric interface  400  housed at the reel  310  and configured for converting electronic signals to optical signals and vice versa so as to allow communication between the line  101  and the hub  344  (see  FIG. 4A ). Similarly, the downhole opto-electric interface  115  is provided at the downhole end of the assembly  100  so as to allow communication between the electrically powered tools  125 ,  150  and the line  101  (see  FIG. 4B ). 
     Referring now to  FIGS. 4A and 4B , with added reference to  FIG. 3 , the above described opto-electric interfaces  400 ,  115  are depicted. As indicated, the surface interface  400  is configured to wirelessly communicate with a surface control unit  342  via a transceiver hub  344 . From the hub  344 , electronic signal may be processed through data protocol  410  and converter  430  boards, ultimately exchanging electronic signal for optical signal via an optical transmitter  440  and receiver  450 . That is, while incoming optical signal may be received by the receiver, outgoing signal may leave the surface interface  400  as light by way of the transmitter  440 . The transmitter  440  may be a conventional broadband fiber optic light source such as a traditional light emitting diode or a laser diode. Additionally, it is worth noting that the exchange of data between the downhole assembly  100  and the control unit  342  includes data for directing a battery  490  associated with the downhole tools  125 ,  150 . Thus, a dedicated port  420  is provided at the surface interface  400  for channeling of such data. 
     In  FIG. 4B , the fiber optic line  101  is depicted with the separate fibers  250 ,  255  individually terminating at the downhole interface  115 . More specifically, the fibers  250 ,  255  emerge from the protective casing  225 , to couple with a downhole light source  441  and receiver  451 . Note that each fiber is dedicated to either uphole or downhole data transmission. That is, in the embodiment shown, the transmission fiber  250  directs signal downhole whereas the return fiber  255  directs signal uphole. However, in other embodiments, the line  101  may employ non-dedicated fiber utilizing two way transmission (e.g. over differing frequencies). Regardless, once terminating, the fibers are exchanged for electrical circuitry that is routed through a pressure barrier  460 . In this manner, the downhole tools  125 ,  150  may be isolated from any well or application fluids present within the coiled tubing  110 . Nevertheless, the circuitry alone continues on to a converter  470  and power  480  boards. Ultimately signal is carried to the battery  490  for directing actuation of the downhole tools  125 ,  150 . In the embodiment shown, the tools  125 ,  150  are linked to the battery  490  through a downhole coupling  495  which may include conventional disconnect and quickstab features. 
     Referring now to  FIGS. 5A and 5B , enlarged depictions of the production region  375  of  FIG. 3  are shown. The production region  375  includes formation perforations extending from the well  380  and into the adjacent formation  395 . Yet, as a production logging application is run, with the logging tool  150  entering the region  375 , the emerging production profile may reveal a production issue. That is, as depicted in  FIG. 5A , a build-up of debris  377  may affect the expected production in the region  375 . Therefore, as depicted in  FIG. 5B , a review of the production profile may lead to continued advancement of the assembly  100  for positioning of the treatment tool  125  to the region  375 . Due to the nature of the fiber optic communications employed as detailed hereinabove, the treatment tool  125  may be employed in real-time to remove the debris  377 . In the embodiment shown, the debris  377  may be scale that is broken down by way of an appropriate acidizing agent  500  emitted through perforations  135  in the tool  125 . 
     Referring now to  FIG. 6 , a flow-chart summarizing an embodiment of employing an optical coiled tubing log assembly is depicted. As indicated at  620  and  630  a control unit and coiled tubing equipment are delivered to a well site at an oilfield. The control unit may be no more than a laptop computer with the capacity to wirelessly direct a logging application and potentially any follow-on treatment applications. As noted, the coiled tubing is equipped with a fiber optic line. Additionally, as indicated at  650 , a logging tool will eventually be coupled to the coiled tubing and the fiber optic line (e.g. through an opto-electric interface if necessary). Thus, a logging application may be run in the well (see  670 ) as directed by the control unit. 
     As indicated at  660 , certain treatment tools may also be coupled to the coiled tubing and fiber optic line in advance of the logging application. Thus, a subsequent treatment application may be run as indicated at  680  without necessarily removing or replacing the coiled tubing with one configured exclusively for treatment. As detailed above, this is made practical by the narrow profile of the line, coupled to the tools through any necessary opto-electric interfacing (as also noted). Of course, in alternate embodiments however, the optical coiled tubing log assembly may be removed and reconfigured or replaced with an assembly directed solely at treatment. In either case, the entire operation may continue to be directed by the small footprint of a single control unit which may consist of no more than a laptop computer. 
     Embodiments described hereinabove include a coiled tubing log assembly that avoids use of an electronic cable therethrough for powering and communications. Thus, higher speed more reliable communications are achieved while simultaneously leaving the coiled tubing substantially un-occluded. As a result, treatment applications may also be run through the assembly as desired. Such treatment applications may even take place without undue concern over damage to the communication line. Thus, an improved assembly may be realized that reduces time, equipment and expense when running coiled tubing based logging applications followed by treatment applications. 
     The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.