Patent Publication Number: US-2022220840-A1

Title: Fatigue monitoring of coiled tubing in downline deployments

Description:
CROSS REFERENCE TO RELATED APPLICATION 
     The present application is a Continuation of U.S. patent application Ser. No. 16/489,763, filed Aug. 29, 2019, which is a U.S. National Stage patent application of International Patent Application No. PCT/US2017/034835, filed on May 26, 2017, the entire content of each of which is hereby incorporated by reference herein. 
    
    
     BACKGROUND 
     The present disclosure relates generally to monitoring operational forces imparted to a coiled tubing strand, e.g., a coiled tubing strand employed for oil and gas exploration, drilling and production. More particularly, embodiments of the disclosure relate to systems and methods for real-time monitoring of high-cycle fatigue in the coiled tubing strand. 
     In operations related to the production of hydrocarbons from subterranean geologic formations, coiled tubing is often employed to facilitate wellbore drilling, maintenance, treatment, stimulation and other wellbore processes. Coiled tubing generally includes a continuous strand of a flexible tube that may be wound and unwound from a reel. The length of a coiled tubing strand may be in the range of about 100 feet to over 30,000 feet in some instances, and thus, the coiled tubing strand may be unwound from a spool to readily lower a downhole tool to a subterranean and/or subsea location. 
     Operational forces may fatigue the coiled tubing strand, which affects the operational life of the coiled tubing strand. Low-cycle fatigue is characterized by high amplitude and low frequency plastic strains, which may be imparted to a coiled tubing strand, e.g., by winding and unwinding the coiled tubing strand from the reel. High-cycle fatigue is characterized by low amplitude and high frequency elastic strains, which may be imparted to a coiled tubing strand, e.g., by waves and ocean currents in an offshore deployment. Both low-cycle fatigue and high-cycle fatigue affect the operational life span of a particular coiled tubing strand. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The disclosure is described in detail hereinafter, by way of example only, on the basis of examples represented in the accompanying figures, in which: 
         FIG. 1  is a partially cross-sectional side view of an offshore coiled tubing deployment system including a fatigue tracking system for monitoring high-cycle fatigue and low-cycle fatigue of a coiled tubing strand; 
         FIG. 2  is an enlarged view of a data acquisition system of the fatigue tracking system of  FIG. 1  illustrating various sensors for detecting operational stresses imparted to the coiled tubing strand; 
         FIG. 3  is a block diagram of the data acquisition system of  FIG. 2 ; and 
         FIG. 4  is a flowchart illustrating an operational procedure for monitoring both high-cycle fatigue and low-cycle fatigue of the coiled tubing strand of  FIG. 1 . 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure includes systems and methods for real-time coiled tubing fatigue monitoring that can establish the remaining operational life of a coiled tubing strand. Each time the coiled tubing strand is deployed, the coiled tubing strand incurs standard (low-cycle) plastic fatigue in bending as the coiled tubing string bends from a reel through a guide arch. Also, the coiled tubing strand experiences smaller, but higher frequency loads (high-cycle) that impart elastic strains in the coiled tubing, e.g., due to interaction with an oceanic environment. A plurality of weight detectors may be coupled to a support frame below the guide arch that receives the coiled tubing strand from the reel. Signals provided by the plurality of weight detectors may be monitored to determine the directionality and magnitude of forces that impart elastic strains to coiled tubing strand. The remaining operational life may be calculated based in part on the elastic strains using a high-cycle fatigue analysis. Plastic strains may also be monitored with strain and/or gyroscopic sensors coupled to a tubing guide or to other equipment. The remaining operational life of the coiled tubing strand may be calculated based on both the elastic and plastic strains. As a result, an operator may be provided with an accurate fatigue history file that maps the fatigue assumed by the coiled tubing at any given point along its length. 
       FIG. 1  is a partially cross-sectional side view of an offshore coiled tubing deployment system  100  including a fatigue tracking system  102  for monitoring high-cycle and low cycle fatigue of a coiled tubing strand  106 . The coiled tubing deployment system  100  may include or otherwise be used in conjunction with an offshore rig or vessel  108  configured to operate in an offshore environment that includes a body of water “B.” In some embodiments, as illustrated, the offshore vessel  108  may comprise a floating service vessel or boat. In other embodiments, however, the offshore vessel  108  may comprise any offshore platform, structure, or vessel used in subsea intervention operations common to the oil and gas industry. The body of water “B” may include, but is not limited to, an ocean, a lake, a river, a stream, or any combination thereof. In other embodiments (not shown), the coiled tubing deployment system  100  may be used in conjunction with an onshore or terrestrial surface reference location. 
     The offshore vessel  108  may be used to deploy the coiled tubing strand  106  into a deployed location such as the body of water “B” for various subsea purposes. For example, the coiled tubing string  106  may be deployed for intervention in a subterranean wellbore “W” with a well intervention tool “T.” The wellbore intervention tool “T” may be lowered on the coiled tubing strand  106  through a subsea wellhead “H” positioned on the ocean floor “F.” In the embodiments illustrated in  FIG. 1 , the wellbore intervention tool “T” is employed in a riser-less subsea operation wherein the coiled tubing strand  106  extends directly through the body of water “B.” In other embodiments, the coiled tubing strand  106  may extend through a riser (not shown) extending between the offshore vessel  108  and the wellhead “H.” In some embodiments, the coiled tubing strand  106  may comprise a conduit or umbilical used to convey fluids or power to the wellhead “H,” a submerged platform (not shown), a subsea pipeline (not shown) or to any other subsea location. The coiled tubing strand  106  may be made of a variety of deformable materials including, but not limited to, a steel alloy, stainless steel, titanium, other suitable metal-based materials, thermoplastics, composite materials (e.g., carbon fiber-based materials), and any combination thereof. The coiled tubing strand  106  may exhibit a diameter of about 3.5 inches, but may alternatively exhibit a diameter that is greater or less than 3.5 inches, without departing from the scope of the disclosure. 
     The coiled tubing strand  106  may be deployed from a reel  110  positioned on a deck  112  of the offshore vessel  108 . The coiled tubing strand  106  may be wound multiple times around the reel  110  for ease of transport. In some embodiments, a fluid source  114  may be communicably coupled to the coiled tubing strand  106  via a fluid conduit  116 . The fluid source  114  may be configured to convey a pressurized fluid, such as a gas or a liquid, into the coiled tubing strand  106 . The presence and amount of pressure in the coiled tubing strand  106  may affect the mechanical strength of the coiled tubing strand  106 . For instance, depending on whether or not the coiled tubing strand  106  is pressurized, more or less bending may be imparted in the coiled tubing strand  106  during operation. Low fluid pressure will result in a first bending potential, while higher fluid pressure will result in a second bending potential. 
     From the reel  110 , the coiled tubing strand  106  may be fed into a guide arch  116 , commonly referred to in the oil and gas industry as a “gooseneck.” The guide arch  116  redirects the coiled tubing strand  106  toward an optional tubing guide  118 , which is operatively coupled to the guide arch  116  and fixed to a frame or the deck  112  of the offshore vessel  108 . As used herein, the term “operatively coupled” refers to a direct or indirect coupling engagement between component parts of the coiled tubing deployment system  100 . In some embodiments, for instance, the tubing guide  118  may be directly coupled to the guide arch  116 . In other embodiments, as illustrated, the tubing guide  118  may be indirectly coupled to the guide arch  116  with one or more structural components interposing the tubing guide  118  and the guide arch  116 . The guide arch  116  may comprise a rigid structure that exhibits a known radius. As the coiled tubing strand  106  is conveyed through the guide arch  116 , the coiled tubing strand  106  may be plastically deformed and otherwise re-shaped and re-directed for receipt by the tubing guide  118  located there below. 
     The tubing guide  118  may be any device or structure used to convey the coiled tubing strand  106  into the body of water “B.” In some embodiments, the tubing guide  118  may comprise a “bend stiffener,” for example. In the illustrated embodiment, the tubing guide  118  may include an optional flange  120  and an optional tapering body  122 . The flange may rest on the deck  112  of the offshore vessel  108 , and the tapering body  122  may extend from the flange  120  through the deck  112  of the offshore vessel  108 . In some embodiments, as illustrated, the tapering body  122  may extend to the body of water “B” such that the coiled tubing strand  106  is deployed directly into the body of water “B”. 
     The flange  120  may operate to support the tubing guide  118  on the offshore vessel  108 , and may also provide a connection location to attach the components located thereabove. Thus, a type of riser is effectively formed for the coiled tubing strand  106 , i.e., the coiled tubing strand  106  extends through components located above the tubing guide and through the tubing guide  118  into the body of water “B”. Accordingly, the flange  120  may be characterized as any box-type frame or other structure capable of accomplishing the aforementioned tasks. Moreover, it will be appreciated, that the tubing guide  118  may be alternatively secured to the offshore vessel  108  in a variety of other ways, without departing from the scope of the disclosure. For instance, in some embodiments, the offshore vessel  108  may include a moon pool (not shown) and the tubing guide  118  may be secured to the offshore vessel  108  at or near the moon pool such that the coiled tubing strand  106  is deployed into the body of water “B” through the moon pool. 
     The tubing guide  118  may be configured to protect the coiled tubing strand  106  at a critical point of high stress assumed by the coiled tubing strand  106 . The tubing guide  118  may be made of a material similar to that of the coiled tubing strand  106  and, therefore, the tubing guide  118  may be configured to reinforce the mechanical properties (e.g., rigidity) of the coiled tubing strand  106  as the coiled tubing strand  106  traverses the tubing guide  118 . The size of the tubing guide  118 , such as the thickness of the tapering body  122 , may serve to spread critical loads assumed by the coiled tubing strand  106  over the length of the tubing guide  118 , which may help improve the working life of the coiled tubing strand  106 . In some embodiments, the tubing guide  118  may include a liner (not shown) that directly contacts the coiled tubing strand  106  as it passes through the tubing guide  118 . As will be appreciated, this may prove advantageous in preventing the materials of the tubing guide  118  and the coiled tubing strand  106  from abrasive contact against one another. 
     In some embodiments, as illustrated, an injector  124  and a support frame  126  may be secured to the offshore vessel  108 , and both the injector  124  and the support frame  126  may interpose the guide arch  116  and the tubing guide  118 . In some embodiments, the support frame  126  may be included to couple the injector  124  to the tubing guide  118 . The injector  124  may be configured to advance or retract the coiled tubing strand  106  during deployment of the coiled tubing strand  106 . In some embodiments, for example, the injector  124  may include a plurality of internal gripping elements or wheels (not shown) configured to engage the outer surface of the coiled tubing strand  106  to either pull the coiled tubing strand  106  from the reel  110  and into the tubing guide  118 , or retract the coiled tubing strand  106  from the body of water “B” to be wound again on the reel  110 . In some embodiments, however, the injector  124  may be omitted. For example, the weight of the coiled tubing strand  106  may instead be relied upon for deployment of the coiled tubing strand into the body of water “B,” and the reel  110  may be motorized to retract the coiled tubing strand  106 . 
     The support frame  126  may be configured to transfer the weight assumed by the injector  124  to the deck  112  of the offshore vessel  108 . In embodiments where the injector  124  is omitted, the support frame  126  may couple the guide arch  116  to the tubing guide  118  or directly to the deck  112  of the offshore vessel  108 . 
     As the coiled tubing strand  106  is unwound from the reel  110  and fed through the guide arch  116  and the tubing guide  118 , it is plastically deformed. This cycled bending is naturally repeated in reverse upon retracting the coiled tubing strand  106  to be wound back around the reel  110 . Moreover, additional forces and bending stresses can be assumed by the coiled tubing strand  106  as it enters the body of water “B,” particularly in riser-less subsea applications, as illustrated in  FIG. 1 . More particularly, in cases where the body of water “B” is open ocean, subsea currents, ocean heaving, waves, and other dynamic oceanic phenomena can all place strain and bending stress on the coiled tubing strand  106  as it is deployed. Over time, these bend cycles include both plastic and elastic strains in the coiled tubing strand  106 , which may result in considerable fatigue, ultimately affecting the overall operational life of the coiled tubing strand  106 . 
     Bending forces assumed by the coiled tubing strand  106  between the reel  110  and the injector  124  can be generally ascertained using known parameters, such as the diameter of the coiled tubing strand  106 , the radius of the guide arch  116 , and the pressure within the coiled tubing strand  106 . Ascertaining the bending forces assumed by the coiled tubing strand  106  at or following the tubing guide  118 , however, can be less certain in view of the unpredictable dynamic environment of the body of water “B,” which provides essentially no known variables. According to embodiments of the present disclosure, the bending forces assumed by the coiled tubing strand  106  at or following the tubing guide  118  may be monitored and quantified in real-time and those measurements may be mapped along the length of the coiled tubing strand  106  to determine fatigue life of the coiled tubing strand  106 . 
     To monitor the bending and fatigue of the coiled tubing strand  106  in real-time, the fatigue tracking system  102  is provided with the coiled tubing deployment system  100 . The fatigue tracking system  102  may provide a reliable method for establishing and recording, both in real-time and in memory mode, the bending forces that induce both plastic and elastic strains assumed by the coiled tubing strand  106 , e.g., at or near the tubing guide  118  and otherwise in the region between the reel  110  and the body of water “B.” As described below, the fatigue tracking system  102  may be configured to record the resultant forces and bending levels encountered by the coiled tubing strand  106  and link those measurements back to the location along the length of the coiled tubing strand  106  where the forces were assumed. As a result, induced fatigue and the corresponding level of bending for each section of the coiled tubing strand  106  run through the coiled tubing deployment system  100  may be established and mapped back into a fatigue history file. Once segments of the coiled tubing strand  106  begin to reach predetermined fatigue limits as based on the fatigue history file, an operator may consider retiring the coiled tubing strand  106  to avoid failure. 
     As illustrated, the fatigue tracking system  102  may include a plurality of load cells, sensors and/or other devices, each communicably coupled to a data acquisition system  130 . The data acquisition system  130  is configured to receive and process signals deriving from each load cell, sensor and/or device. The data acquisition system  130  may be a computer system, for example, that includes a memory, a processor, and computer readable instructions that, when executed by the processor, process the sensor signals to provide an output signal  132 . Data corresponding to the construction parameters of the coiled tubing strand  106  may be provided to the data acquisition system  130  for reference. For instance, construction parameters of the coiled tubing strand  106  loaded into the data acquisition system  130  may include material grade, length, outer diameter, and inner diameter of the coiled tubing strand  106 . Additional construction parameters that may be loaded into the data acquisition system  130  include the location of segment welds or joints along the body of the coiled tubing strand  106 . The construction parameters may be used by the data acquisition system  130  as reference points in generating the fatigue history file. 
     The fatigue tracking system  102  may further include a pressure transducer or sensor  134  used to measure the real-time pressure within the coiled tubing strand  106  during operation. The pressure sensor  134  may be fluidly coupled to the coiled tubing strand  106  and, more particularly, communicably coupled to the coiled tubing strand  106  at the fluid conduit  116 , which, as mentioned above, provides pressurized fluid into the coiled tubing strand  106  from the fluid source  114 . The real-time pressure detected by the pressure sensor  134  may be transmitted to the data acquisition system  130  for processing. More particularly, the data acquisition system  130  may take into consideration the detected pressure in calculating fatigue on the coiled tubing strand  106  since the internal pressure may affect the mechanical strength of the coiled tubing strand  106 . 
     In the illustrated embodiment, the fatigue tracking system  102  may also include one or more depth counters  136   a ,  136   b  (collectively  136 ) located at fixed points along the path traversed by the coiled tubing strand  106  through the coiled tubing deployment system  100 . In some embodiments, a first depth counter  136   a  may be located at or immediately after the reel  110 . Additionally or alternatively, a second depth counter  136   b  may be located immediately below the injector  124  and otherwise between the reel  110  and the tubing guide  118 . The depth counters  136   a ,  136   b  may comprise any measurement devices capable of monitoring how much length of the coiled tubing strand  106  is deployed from the reel  110  and bypasses the depth counters  136   a ,  136   b . In some embodiments, for instance, the depth counters  136   a ,  136   b  may include a depth wheel that physically engages the coiled tubing strand  106  while it turns to register the traversed length of the coiled tubing strand  106 . In some other embodiments, however, the depth counters  136   a ,  136   b  may comprise an optical measurement device, such as a laser sight capable of converting optical images into distance measurements. 
     Measurements obtained by the depth counters  136   a ,  136  may be transmitted to the data acquisition system  130  for processing. As will be appreciated, knowing the length of the coiled tubing strand  106  deployed, may allow the data acquisition system  130  to map the coiled tubing strand  106  and correlate specific real-time weight, strain or bend measurements with the precise location where such forces were assumed by the coiled tubing strand  106 . Accordingly, the measured distance or length may be mapped over time and correlated to high-cycle and low-cycle fatigue at known points along the coiled tubing strand  106 , which form part of the fatigue history file. 
       FIG. 2  is an enlarged view of the data acquisition system  130  of the fatigue tracking system  102  illustrating various sensors disposed below the guide arch  116  for detecting operational stresses imparted to the coiled tubing strand  106 . With reference to  FIG. 2  and continued reference to  FIG. 1 , the fatigue tracking system  102  includes one or more load cells, transducers, weight sensors or other weight detectors  137   a ,  137   b ,  137   c    137   d  (collectively  137 ) that may be employed to measure a characteristic value indicative of the real-time surface weight of the coiled tubing strand  106 , e.g., a portion of the weight of the coiled tubing strand  106  carried by the guide arch  116 , during operation of the coiled tubing deployment system  100 . In some embodiments, the characteristic value may include acceleration, deceleration, stress, strain and/or, of course, weight. The weight detectors  137  may be sensitive to real-time changes in mass, acceleration and force on the guide arch  116 , and may be coupled indirectly to the guide arch  116  and/or coiled tubing strand  106 . More particularly, the weight detectors  137  may be coupled to structural components between the guide arch  116  and the deck  110  of the offshore vessel  108  that transfers the weight of the coiled tubing  106  onto the deck  110 . In some embodiments, a first plurality of weight detectors  137   a ,  137   b  are disposed between the injector  124  and the support frame  116 . The weight detectors  137   a ,  137   b  are disposed at distinct locations around the coiled tubing strand  106 , and thus, a directionality of forces imparted to the coiled tubing strand may be determined from the weight detectors  137   a ,  137   b . Although only two weight detectors  137   a  and  137   b  are illustrated between the injector  124  and the support frame  126 , three or more weight detectors  137  may be disposed in a circular array around the coiled tubing strand  106 . In some embodiments, e.g., embodiments where the injector  124  is omitted, the weight detectors  137  may additionally or alternatively be coupled between the support frame  126  and the deck  112  as illustrated by weight detectors  137   c ,  137   d.    
     Additional or alternative weight detectors  137  may be provided via a mechanism (not shown) that transfers the weight of the coiled tubing strand  106  onto the deck  112  of the offshore vessel  108 . Such a mechanism may comprise, for example, a work window into which a set of slip rams can be used to hold stationary the coiled tubing strand  106  or via a load cell located directly below the guide arch  116 . The real-time weight measurements detected by the weight detector  137  may be transmitted to the data acquisition system  130  for processing and the data acquisition system  130  may take into consideration the detected weight in calculating fatigue on the coiled tubing strand  106 . It has been determined that weight measurements may be particularly indicative of the forces imparting elastic strains to the coiled tubing strand  106 . Weight measurements provided by the weight detectors  137  may also be employed to detect heave and movement of the offshore vessel  108 , thereby permitting the fatigue tracking system  102  to remove or allow for motion effects of the offshore vessel  108  from the weight measurement signals and/or accelerometer signals. 
     The fatigue tracking system  102  may optionally include a plurality of bend sensors  138   a ,  138   b ,  138   c  (collectively, bend sensors  138 ). A first set of bend sensors  138   a  is located at a first location on the tubing guide  118 . More particularly, the first set of bend sensors  138   a  may be coupled to the tapered body  122  below the flange  120  and may be configured to measure real-time strain assumed by the coiled tubing strand  106  as it is deployed into the body of water “B”. The first set of bend sensors  138   a  may include at least one of a strain sensor and a gyroscopic sensor used to determine the strain on the coiled tubing strand  106  at the first location. The highest strain readings and critical bending points for the coiled tubing strand  106  following the guide arch  116  will be at the tubing guide  118  just below the flange  120 . And since the coiled tubing strand  106  may be continuously or continually be moving through the tubing guide  118 , the first set of bend sensors  138   a  may be coupled to the tubing guide  118  at the first location, and the strain measured on the tubing guide  118  may be indicative of the strain assumed by a particular section of the coiled tubing strand  106  as that particular section passes through the first location on the tubing guide. Sensor signals derived from the first set of bend sensors  138   a  may be transmitted to the data acquisition system  130  for processing. 
     In some embodiments, the fatigue tracking system  102  may additionally or alternatively include additional bend sensors  138 , illustrated as a second set of bend sensors  138   b  located at a second location on the tubing guide  118 , and a third set of bend sensors  138   c  located at a third location on the tubing guide  118 . The second and third locations may be below the first location and otherwise at locations along the tapered body  122  that exhibit smaller thicknesses as compared to the first location. Similar to the first set of bend sensors  138   a , the first and/or second sets of bend sensors  138   b ,  138   cc  may include at least one of a strain sensor and a gyroscopic sensor used to determine the strain on the coiled tubing strand  106  at the second and third locations, respectively. As will be appreciated, the bending assumed by the coiled tubing strand  106  may be more severe or pronounced nearer the end of the tubing guide  118 . The second and third sets of bend sensors  138   b ,  138   c  may be configured to detect and report this resultant movement. Sensor signals derived from the second and third sets of bend sensors  138   b ,  138   c  may be transmitted to the data acquisition system  130  for processing. As will be appreciated, the length of the tubing guide  118  may vary from project to project and, as a result, the number of sets of bend sensors  138   a - c  may also vary for optimization. Moreover, since the obtained data will be recorded and matched to known segments or intervals of the coiled tubing strand  106 , an increased number of locations to collect data points along the tubing guide  118  may enable increased accuracy. 
     In some embodiments, the fatigue tracking system  102  may further include a set of reference sensors  140  located at generally stationary position with respect to the deck  112  of the offshore vessel  108 , e.g., at a point on the support frame  126  just above the tubing guide  118 , or otherwise above the anticipated critical bending point in the coiled tubing strand  106 . The reference sensors  140  may include a strain sensor, an accelerometer, and/or a weight detector to monitor and detect heave and movement of the surface vessel  102  during operation. Sensor signals derived from the reference sensors  140  may be transmitted to the data acquisition system  130  for processing. As illustrated, the reference sensors  140  are depicted as being coupled to the support frame  126 . However, the reference sensors  140  may alternatively be coupled at any fixed point above the tubing guide  118  and below the guide arch  116 , without departing from the scope of the disclosure. In some embodiments, a strain sensor of the reference sensors  140  may be located between the guide arch  116  and the tubing guide  118 , while an accelerometer and/or weight detectors (not shown) of the reference sensors  140  may be fixedly attached to the deck  112  of the offshore vessel  108 , or at another location remote from the strain sensor  108  to detect the heave and movement of the offshore vessel  108  during operation. 
     Referring to  FIG. 2 , the reference sensors  140  are illustrated as being positioned on a spool riser  141  coupled to the support frame  126  above the tubing guide. The support frame  126  is depicted as interposing the injector  124  and the tubing guide  118 , and, according to one or more embodiments, the support frame  126  may operate as a work window and thereby facilitate access to the coiled tubing strand  106  and reference sensors  140 . In some embodiments, the fatigue tracking system  102  may include multiple sets of reference sensors  140 , without departing from the scope of the disclosure. In some embodiments, the fatigue tracking system  102  may include multiple sets of sensors  137 , but have no injector  124 , without departing from the scope of the disclosure. 
     The measurements obtained by the reference sensors  140  may provide a control point or offset that may be applied to the measurements obtained by the weight detectors  137  and/or bend sensors  138 . More particularly, the data acquisition system  130  may apply the measurements derived from the reference sensors  140  to the measurements derived from the weight detectors  137  and bend sensors  138  to remove the effects of motion of the offshore vessel  108  and the effects of forces and strains imparted to the coiled tubing strand at locations remote from the weight detectors  137  and bend sensors  138 . Accordingly, in some embodiments, the data acquisition system  130  may process the sensor signals derived from the weight detectors  137  and bend sensors  138  in view of reference measurements derived from the reference sensors  140 . 
     Each of the sensors  134 ,  137 ,  138 ,  140  and the depth counter  136  may be communicably coupled to the data acquisition system  130  and configured to transmit corresponding measurements thereto in real-time via any known means of telecommunication or data transmission. In some embodiments, for instance, the data acquisition system  130  may be physically wired to one or more of the sensors  134 ,  137 ,  138 ,  140  and the depth counter  136 , e.g., through electrical or fiber optic lines. In other embodiments, one or more of the sensors  134 ,  137 ,  138 ,  140  and the depth counter  136  may be configured to wirelessly communicate with the data acquisition system  130 , such as via electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, radio frequency transmission, or any combination thereof. 
     In some embodiments, as illustrated, the data acquisition system  130  may be arranged at or near the offshore vessel  108 . In other embodiments, the data acquisition system  130  may be remotely located and the sensors  134 ,  137 ,  138 ,  140  and the depth counter  136  may be configured to communicate remotely with the data acquisition system  130  (either wired or wirelessly). The data acquisition system  130  may be configured to receive and process the various signals from the sensors  134 ,  137 ,  138 ,  140  and the depth counter  136  in conjunction with the construction parameters of the coiled tubing strand  106 . The relative distances between the sensors  134 ,  137 ,  138 ,  140  and the depth counter  136  may also be used as configurable parameters within the data acquisition system  130  in generating the output signal  132 . 
     The output signal  132  may comprise real-time elastic and plastic bending data corresponding to specific locations along the length of the coiled tubing strand  106 . In some embodiments, such data may be stored for future reference or consideration. In other embodiments, however, the output signal  132  may be transmitted to a peripheral device  142  for consideration and/or review by an operator in real-time. The peripheral device  142  may include, but is not limited to, a monitor (e.g., a display, a GUI, a handheld device, a tablet, etc.), a printer, an alarm, additional storage memory, etc. In some embodiments, the peripheral device  142  may be configured to provide the operator with a graphical output or display that charts or maps the length of the coiled tubing strand  106  versus estimated fatigue on the coiled tubing strand  106  at any given location. Accordingly, given that fatigue life of the coiled tubing strand  106  is largely a matter of repeated usage, the data acquired by the data acquisition system  130  may be stored and historically tied to the specific coiled tubing strand  106  and thereby form part of the fatigue history file corresponding to the coiled tubing strand  106 . 
       FIG. 3  is a block diagram of the data acquisition system  130 . With reference to  FIG. 3 , and continued reference to  FIG. 1 , the data acquisition system  130  may include a bus  202 , a communications unit  204 , one or more controllers  206 , a non-transitory computer readable medium (i.e., a memory)  208 , a computer program  210 , and a library or database  212 . The bus  202  may provide electrical conductivity and a communication pathway among the various components of the data acquisition system  130 . The communications unit  204  may employ wired or wireless communication technologies, or a combination thereof. The communications unit  204  can include communications operable among land locations, sea surface locations both fixed and mobile, and undersea locations both fixed and mobile. The computer program  210  may be stored partially or wholly in the memory  208  and, as generally known in the art, it may be in the form of microcode, programs, routines, or graphical programming. 
     The bus  202  is communicatively coupled to the sensors  134 ,  137 ,  138 ,  140  and the depth counters  136  such that the data acquisition system  130  may receive and sample one or more signals derived from the sensors  134 ,  137 ,  138 ,  140  and the depth counters  136 . The controller  206  may be configured to transfer the sensor signals to the memory  208 , which may encompass at least one of volatile or non-volatile memory. The computer program  210  may be configured to access the memory  208  and process the sensor signals in real-time. In some embodiments, however, the sensor signals may be logged or otherwise stored in the memory  208  or the database  212  for post-processing review or analysis. 
     In processing the sensor signals, the computer program  210  may be configured to digitize the sensor signal and generate digital data. The computer program  210  may employ pre or post-acquisition processing by applying one or more signal amplifiers and/or signal filters (e.g., low, medium, and/or high-pass frequency filters) in hardware or software. In some embodiments, the computer program  210  may be configured to output the acquired signal in the time domain, thereby providing a time domain output. In another embodiment, the computer program  210  may also be capable of transforming and outputting the digital data in the frequency domain, thereby providing a frequency domain output. This transformation into the frequency domain may be accomplished using several different frequency-based processing methods including, but not limited to, fast Fourier transforms (FFTs), short-time Fourier transforms (STFTs), wavelets, the Goertzel algorithm, or any other domain conversion methods or algorithms known by those skilled in the art. In some embodiments, one or both of the time domain and frequency domain signals may be filtered using at least one of a low-pass filter, a medium-pass filter, and a high-pass filter or other types of filtering techniques, without departing from the scope of the disclosure. 
     The computer program  210  may further be configured to query the database  212  for stored data corresponding to construction parameters of the coiled tubing strand  106  and relative distances between the sensors  134 ,  137 ,  138 ,  140  and the depth counters  136 . Upon querying the database  212 , the computer program  210  may be able to apply the construction parameters and relative distances to the measured signals. The computer program  210  may then deliver the output signal  132  comprising real-time, elastic strain and plastic strain bending data corresponding to specific locations along the length of the coiled tubing strand  106 . In some cases, as indicated above, the output signal  132  may be provided to the peripheral device  142  for display. In other embodiments, or in addition thereto, the data acquired by the data acquisition system  130  may be stored and historically tied to the fatigue history file corresponding to the coiled tubing strand  106 . 
       FIG. 4  is a flowchart illustrating an operational procedure  300  for monitoring both high-cycle fatigue and low-cycle fatigue of the coiled tubing strand  106 . Referring to  FIG. 4 , and with continued reference to  FIGS. 1-3 , the operational procedure  300  begins at step  302  where the coiled tubing strand  106  is deployed from the reel  110  on the offshore vessel  108 . The coiled tubing strand  106  is received over the guide arch  116  and is conveyed into the body of water “B” below the offshore vessel  108  (step  304 ). In some embodiments, the coiled tubing strand  106  may be conveyed directly through the body of water “B” and into a wellbore “W” to support a wellbore intervention tool “T” therein. 
     Next, at step  306 , a surface weight of the coiled tubing  106 , e.g., a real-time weight of the coiled tubing strand  106  carried by the guide arch  116 , is measured with a plurality of weight detectors  137  disposed around the coiled tubing strand  106 . The measured surface weight has been determined to be a more reliable indicator of elastic strain than other measurable parameters related to the deployment of the coiled tubing strand  106 . Thus, an elastic strain of the coiled tubing strand  106  is determined, estimated or calculated based on the measured weight of the coiled tubing strand  106  (step  308 ). A directionality of the elastic strain imparted to the coiled tubing strand  106  may be determined from the measurement of the surface weight from a plurality of weight detectors  137  disposed at distinct locations surrounding the coiled tubing strand  106 . The elastic strain may be determined, estimated or calculated based on the measured weight of the coiled tubing strand, and/or from additional measured parameters of the coiled tubing strand. For example, measurements from bend sensors  138  may be more indicative of elastic strains than the measurements of the weight detectors  137 . Thus, the bend sensors  138  may be additionally or alternatively employed to determine the elastic strains. 
     At step  310 , a plastic strain on the coiled tubing strand  106  may be determined from a combination of the geometries of the components of the offshore coiled tubing deployment system  100  (known or measured) together with parameters measured by the fatigue tracking system  102 . For example, the known radius associated with the guide arch  116 , the dimensions of the reel  110 , and the known geometry of the coiled tubing strand  106  stored on the reel  110  may be used together with the internal pressure inside the coiled tubing strand  106  measured by the pressure sensor  134 , the measurements of the weight detectors  137  and/or bend sensors  138  to determine the plastic strain. 
     Steps  306 - 310  may be continuously or continually repeated throughout a deployment of the coiled tubing strand  106 . A fatigue history file that maps the fatigue assumed by the coiled tubing at any given point along its length may be generated for the particular deployment, and the fatigue history file may be associated with the particular coiled tubing strand  106 . 
     A remaining operational life of the coiled tubing strand  106  based on both the elastic and plastic strains may be determined (step  312 ). The remaining life may be determined at any point in the procedure  300 , and not necessarily at the end of a particular deployment. If it is determined that the remaining operational life is above a predetermined threshold, the procedure may return to step  302  for an additional deployment of the coiled tubing strand  106 . When it is determined that the remaining operational life has reached or fallen below a predetermined threshold, the procedure  300  may advance to step  314  where the coiled tubing strand  106  is removed from operation and retired. 
     The aspects of the disclosure described below are provided to describe a selection of concepts in a simplified form that are described in greater detail above. This section is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining the scope of the claimed subject matter. 
     In one aspect, the disclosure is directed to a method of evaluating a coiled tubing strand. The method includes (a) deploying the coiled tubing strand from a reel positioned at a surface reference location, (b) receiving the coiled tubing strand with a guide arch positioned on surface reference location and conveying the coiled tubing strand below the surface reference location, (c) measuring one or more characteristic values indicative of a weight of the coiled tubing strand carried by the guide arch with at least one weight detector disposed between the guide arch and the surface reference location, thereby generating one or more weight measurement signals, (d) receiving the one or more weight measurement signals with a data acquisition system communicably coupled to the at least one weight detector, (e) processing the one or more weight measurement signals with the data acquisition system to estimate an elastic strain imparted to the coiled tubing strand, and (f) generating an output signal with the data acquisition system indicative of real-time bending fatigue of the coiled tubing strand based on the elastic strain estimated from the one or more weight measurement signals. 
     In one or more example embodiments, measuring the characteristic values indicative of the weight of the coiled tubing strand further includes measuring the characteristic value with a plurality of weight detectors disposed at distinct fixed locations with respect to the surface reference location. In some embodiments, the surface reference location is a deck of an offshore vessel, and the method further includes detecting heave and movement of the offshore vessel and allowing for motion effects of the offshore vessel in at least one of the weight measurement signals, an accelerometer signal and a reference sensor signal received with the data acquisition system. 
     In another aspect, the disclosure is directed to a method of evaluating a coiled tubing strand. The method includes (a) deploying the coiled tubing strand from a reel positioned on an offshore vessel, (b) receiving the coiled tubing strand with a guide arch positioned on the offshore vessel and conveying the coiled tubing strand into a body of water below the offshore vessel, (c) measuring a weight of the coiled tubing strand with at least one weight detector disposed on the offshore vessel, thereby generating one or more weight measurement signals, (d) receiving the one or more weight measurement signals with a data acquisition system communicably coupled to the at least one weight detector, (e) processing the one or more weight measurement signals with the data acquisition system to determine an elastic strain imparted to the coiled tubing strand, and (f) generating an output signal with the data acquisition system indicative of real-time bending fatigue of the coiled tubing strand based on the elastic strain determined from the one or more weight measurement signals. 
     In one or more example embodiments, measuring the weight of the coiled tubing strand further includes measuring the weight of the coiled tubing strand with a plurality of weight detectors disposed at distinct fixed locations with respect to a deck of the offshore vessel. Processing the one or more weight measurement signals may further include determining a directionality of the elastic strain imparted to the coiled tubing strand with weight measurement signals received from the plurality of weight detectors. 
     In some embodiments, the method further includes measuring a real-time elastic strain assumed by the coiled tubing strand with one or more bend sensors, thereby generating one or more bend sensor signals. Generating the output signal may further include generating the output signal based on both the one or more weight measurement signals and the elastic strain measured by the one or more bend sensors. 
     The method, in some embodiments, further includes detecting heave and movement of the offshore vessel and allowing for motion effects of the offshore vessel in at least one of the weight measurement signals, and accelerometer signal and a reference sensor signal received with the data acquisition system. The heave and movement of the offshore vessel may be detected with the at least one weight detector, and/or with a reference sensor. The method may further include determining a remaining operational life of the coiled tubing strand, and may include removing the coiled tubing strand from operation if the remaining operational life of the coiled tubing strand is below a predetermined threshold. 
     In another aspect, the disclosure is directed to a coiled tubing deployment system. The system includes a reel positioned on a surface reference location and coiled tubing strand wound on the reel. A guide arch is positioned on the surface reference location to receive the coiled tubing from the reel and to direct the coiled tubing strand into a deployed location. At least one weight detector is positioned between the guide arch and the surface reference location. The at least one weight detector is operable to measure one or more characteristic values indicative of a surface weight of the coiled tubing strand and operable to generate one or more weight measurement signals. A data acquisition system is communicably coupled to the at least one weight detector to receive and process the one or more weight measurement signals to determine an elastic strain imparted to the coiled tubing strand. The data acquisition system is further operable to generate an output signal indicative of real-time bending fatigue of the coiled tubing strand based on the elastic strain determined from the one or more weight measurement signals. 
     In one or more example embodiments, the at least one weight detector includes a plurality of weight detectors disposed at distinct fixed locations with respect to the surface reference location. The system may further include an injector coupled between the guide arch and surface reference location, and weight detectors of the plurality of weight detectors are disposed in array beneath the injector. In some embodiments, the surface reference location is the deck of an offshore vessel and the deployed location is a body of water on to which the offshore vessel is deployed. The system may further include a wellhead disposed within the body of water, and the coiled tubing strand may extend directly through the body of water between the wellhead and the offshore vessel without a riser. 
     In another aspect, the disclosure is directed to a coiled tubing deployment system. The system includes an offshore vessel having a reel positioned thereon and coiled tubing strand wound on the reel. The offshore vessel is deployable on a body of water. A guide arch is positioned on the offshore vessel to receive the coiled tubing from the reel and to direct the coiled tubing strand through a deck of the offshore vessel and into the body of water. The system also includes at least one weight detector positioned between the guide arch and the deck of the offshore vessel; the at least one weight detector operable to measure a surface weight of the coiled tubing strand and operable to generate one or more weight measurement signals. A data acquisition system is communicably coupled to the at least one weight detector to receive and process the one or more weight measurement signals to determine an elastic strain imparted to the coiled tubing strand. The data acquisition system is further operable to generate an output signal indicative of real-time bending fatigue of the coiled tubing strand based on the elastic strain determined from the one or more weight measurement signals. 
     In one or more exemplary embodiments, the at least one weight detector includes a plurality of weight detectors disposed at distinct fixed locations with respect to a deck of the offshore vessel. The system may optionally include an injector coupled between the guide arch and the deck of the offshore vessel, wherein the plurality of weight detectors are disposed in array beneath the injector. In some embodiments, the system further includes at least one bend sensor operable to measure a strain in the coiled tubing strand and to generate a bend sensor signal indicative of the elastic strain imparted to the coiled tubing strand. The data acquisition system may be operable to determine a real-time bending fatigue of the coiled tubing strand based on both a plastic strain calculated at least in part based on the geometries of the reel and guide arch and the elastic strain determined by the data acquisition system based on at least one of the at least one weight measurement signal and the strain measured by the at least one bend sensor. 
     In some embodiments the system further includes a wellhead disposed within the body of water. The coiled tubing strand may extend directly through the body of water in a riser-less manner between the wellhead and the offshore vessel. 
     In other aspects of the disclosure is directed to a method of evaluating a remaining operational life of a coiled tubing strand. The method includes (a) deploying the coiled tubing strand from a reel positioned on a surface reference location, (b) measuring at least one characteristic value indicative of a surface weight of the coiled tubing strand with at least one weight detector, (c) determining an elastic strain imparted to the coiled tubing strand based on the surface weight of the coiled tubing strand, and (d) estimating the remaining operational life of the coiled tubing strand based on the elastic strain imparted to the coiled tubing strand. 
     In some embodiments, the method further includes measuring the at least one characteristic value at a plurality of fixed locations on the surface reference location with the at least one weight detector. The method may further include injecting the coiled tubing strand into a body of water with an injector disposed on an offshore vessel, and the plurality of fixed locations may be disposed between the injector and a deck of the offshore vessel. 
     In other aspects, the disclosure is directed to a method of evaluating a remaining operational life of a coiled tubing strand. The method includes (a) deploying the coiled tubing strand from a reel positioned on an offshore vessel, (b) measuring a surface weight of the coiled tubing strand with at least one weight detector disposed on the offshore vessel, (c) determining an elastic strain imparted to the coiled tubing strand based on the surface weight of the coiled tubing strand, and (d) estimating the remaining operational life of the coiled tubing strand based on the elastic strain imparted to the coiled tubing strand. 
     In some exemplary embodiments, the method further includes measuring the surface weight of the coiled tubing strand at a plurality of fixed locations on the offshore vessel with the at least one weight detector. The method may further include injecting the coiled tubing strand into the body of water with an injector, and the plurality of fixed locations may be disposed between the injector and a deck of the offshore vessel. 
     The method, in some embodiments, further includes determining a plastic strain imparted to the coiled tubing strand. Estimating the remaining operational life of the coiled tubing strand may further include estimating the remaining operational life of the coiled tubing strand based on both the plastic strain and the elastic strain imparted to the coiled tubing strand. In some exemplary embodiments, the method may further include measuring an elastic strain imparted to the coiled tubing strand, and estimating the remaining operational life of the coiled tubing strand further comprises estimating the remaining operational life of the coiled tubing strand based on both the elastic strain measured and the elastic strain determined based on the surface weight of the coiled tubing strand. Measuring the elastic strain imparted to the coiled tubing strand may include measuring a stain on the coiled tubing strand with at least one bend sensor disposed on a tubing guide extending below a deck of the offshore vessel. 
     The Abstract of the disclosure is solely for providing the United States Patent and Trademark Office and the public at large with a way by which to determine quickly from a cursory reading the nature and gist of technical disclosure, and it represents solely one or more examples. 
     While various examples have been illustrated in detail, the disclosure is not limited to the examples shown. Modifications and adaptations of the above examples may occur to those skilled in the art. Such modifications and adaptations are in the scope of the disclosure.