Patent Publication Number: US-2020291767-A1

Title: Performance based condition monitoring

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to and the benefit of U.S. Provisional Application No. 62/566,889, titled “PERFORMANCE CONDITION MONITORING,” filed Oct. 2, 2017, the entire disclosure of which is hereby incorporated herein by reference. 
    
    
     BACKGROUND OF THE DISCLOSURE 
     Wells are generally drilled into the ground or ocean bed to recover natural deposits of oil, gas, and other materials that are trapped in subterranean formations. Well construction operations (e.g., drilling operations) may be performed at a wellsite by a drilling system having various surface and subterranean equipment operating in a coordinated manner. A drilling system may utilize a drill bit attached to the lower end of a drill string to drill a well. Drilling fluid may be pumped from a wellsite surface down through the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit, and may additionally carry drill cuttings from the wellbore back to the wellsite surface. Wellsite equipment may be grouped into various subsystems, wherein each subsystem performs a different operation controlled by a corresponding local and/or a remotely located controller. 
     Condition monitoring is a process of monitoring equipment condition indicators for changes to identify future faults, failures, breakdowns, and other maintenance problems associated with equipment. Condition monitoring is increasingly utilized in the oil and gas industry as part of predictive maintenance of wellsite (e.g., drilling) equipment. Condition monitoring utilizes condition data generated by peripheral (e.g., add-on) sensors and instruments to gain more insight to the future maintenance problems. Condition data, such as vibration data, acoustic data, thermographic (e.g., infrared signature) data, is used solely to indicate condition of equipment. Condition monitoring also includes analyzing operational data to determine amount of equipment usage and compare the determined equipment usage to expected operational lifetime specifications and/or calculations. 
     However, current condition monitoring products do not provide adequate operational efficiency measurements and analytics for wellsite operations. Such products may provide drill rig state detection, calculations of operational key performance indicators (KPIs), and customized dashboards and reporting tools. Common to such performance monitoring products and services is a top-down monitoring approach, which focuses on performance of an entire piece of equipment and/or system and how such piece of equipment and/or system as a whole contributes to the overall process or operation being performed at the wellsite. For example, drilling operational KPIs help monitor general functionality and/or detect broad operational problems, such as related to performance, non-productive time, and invisible lost time. Such general performance monitoring is capable of determining a reduction in performance on a machine or system level, with limited insight to contextual or specific factors causing such reduction in performance. Thus, current condition monitoring products cannot detect performance reductions affecting a portion or component of a piece of equipment or a small reduction affecting general performance of the piece of equipment. Certain reductions in performance may be recognized by analyzing operational the KPIs of the rig, which may trigger an alarm within the control system. However, alarm thresholds are typically designed with flexibility to handle variations in climate and operational conditions. Thus, current condition monitoring systems will not trigger an alarm unless a decrease in overall performance of equipment is substantial. 
     Furthermore, current condition monitoring products rely on high quantities of peripheral sensors and instrumentation to monitor condition related parameters, such as oil quality, equipment vibration, acoustic emission, temperature, thermography, and electrical current signature. Implementing such products has a high investment cost and mandates expertise to analyze data generated by the peripheral sensors to forecast equipment faults. 
     SUMMARY OF THE DISCLOSURE 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter. 
     The present disclosure introduces a computer program product that includes a non-transitory, computer-readable medium including instructions that, when executed by a processor of a processing system, cause the processing system to receive sensor measurements each generated by a corresponding sensor of a piece of equipment at an oil and gas wellsite. The piece of equipment includes actuators each operable to facilitate a corresponding action performed by a component of the piece of equipment. Each sensor measurement is indicative of a corresponding action. The instructions also cause the processing system to calculate a condition indicator for each sensor based on a corresponding sensor measurement, record each condition indicator over a period of time, and determine condition of the piece of equipment based on at least one of the condition indicators recorded over time. 
     The present disclosure also introduces a method including operating a piece of equipment, at an oil and gas wellsite, by performing actions by a component of the piece of equipment, and generating sensor measurements each indicative of a corresponding action. The method also includes receiving the sensor measurements by a processing system, calculating a condition indicator for each component based on a corresponding sensor measurement, recording each condition indicator over a period of time, and determining condition of the piece of equipment based on at least one of the condition indicators recorded over time. 
     The present disclosure also introduces a system including a piece of equipment at an oil and gas wellsite and a processing system including a processor and a memory storing a computer program code. The piece of equipment includes actuators each operable to facilitate a corresponding action by a component of the piece of equipment, and sensors each operable to generate a signal indicative of an operational parameter associated with a corresponding action. When executed, the computer program code causes the processing system to determine a condition indicator for each action based on a corresponding signal, record each condition indicator over a period of time, and determine condition of the piece of equipment based on at least one of the condition indicators recorded over time. 
     These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. 
         FIG. 1  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 2  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 3  is a flow-chart diagram of at least a portion of a process according to one or more aspects of the present disclosure. 
         FIG. 4  is a flow-chart diagram of at least a portion of a process according to one or more aspects of the present disclosure. 
         FIG. 5  is a flow-chart diagram of at least a portion of a process according to one or more aspects of the present disclosure. 
         FIG. 6  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 7  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 8  is a graph related to one or more aspects of the present disclosure. 
         FIG. 9  is a graph related to one or more aspects of the present disclosure. 
         FIG. 10  is a flow-chart diagram of at least a portion of a method according to one or more aspects of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. 
       FIG. 1  is a schematic view of at least a portion of an example implementation of a well construction system  100  according to one or more aspects of the present disclosure. The well construction system  100  represents an example environment in which one or more aspects of the present disclosure described below may be implemented. Although the well construction system  100  is depicted as an onshore implementation, the aspects described below are also applicable to offshore implementations. 
     The well construction system  100  is depicted in relation to a wellbore  102  formed by rotary and/or directional drilling from a wellsite surface  104  and extending into a subterranean formation  106 . The well construction system  100  includes surface equipment  110  located at the wellsite surface  104  and a drill string  120  suspended within the wellbore  102 . The surface equipment  110  may include a mast, a derrick, and/or another support structure  112  disposed over a rig floor  114 . The drill string  120  may be suspended within the wellbore  102  from the support structure  112 . The support structure  112  and the rig floor  114  are collectively supported over the wellbore  102  by legs and/or other support structures (not shown). 
     The drill string  120  may comprise a bottom-hole assembly (BHA)  124  and means  122  for conveying the BHA  124  within the wellbore  102 . The conveyance means  122  may comprise drill pipe, heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough logging condition (TLC) pipe, coiled tubing, and/or other means for conveying the BHA  124  within the wellbore  102 . A downhole end of the BHA  124  may include or be coupled to a drill bit  126 . Rotation of the drill bit  126  and the weight of the drill string  120  collectively operate to form the wellbore  102 . The drill bit  126  may be rotated from the wellsite surface  104  and/or via a downhole mud motor (not shown) connected with the drill bit  126 . 
     The BHA  124  may also include various downhole tools  180 ,  182 ,  184 . One or more of such downhole tools  180 ,  182 ,  184  may be or comprise an acoustic tool, a density tool, a directional drilling tool, an electromagnetic (EM) tool, a formation sampling tool, a formation testing tool, a gravity tool, a monitoring tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a rotational speed sensing tool, a sampling-while-drilling (SWD) tool, a seismic tool, a surveying tool, a torsion sensing tool, and/or other measuring-while-drilling (MWD) or logging-while-drilling (LWD) tools. 
     One or more of the downhole tools  180 ,  182 ,  184  may be or comprise an MWD or LWD tool comprising a sensor package  186  operable for the acquisition of measurement data pertaining to the BHA  124 , the wellbore  102 , and/or the formation  106 . One or more of the downhole tools  180 ,  182 ,  184  and/or another portion of the BHA  124  may also comprise a telemetry device  187  operable for communication with the surface equipment  110 , such as via mud-pulse telemetry. One or more of the downhole tools  180 ,  182 ,  184  and/or another portion of the BHA  124  may also comprise a downhole processing device  188  operable to receive, process, and/or store information received from the surface equipment  110 , the sensor package  186 , and/or other portions of the BHA  124 . The processing device  188  may also store executable computer programs (e.g., program code instructions), including for implementing one or more aspects of the operations described herein. 
     The support structure  112  may support a driver, such as a top drive  116 , operable to connect (perhaps indirectly) with an uphole end of the conveyance means  122 , and to impart rotary motion  117  and vertical motion  135  to the drill string  120  and the drill bit  126 . However, another driver, such as a kelly and rotary table (neither shown), may be utilized instead of or in addition to the top drive  116  to impart the rotary motion  117 . The top drive  116  and the connected drill string  120  may be suspended from the support structure  112  via hoisting equipment, which may include a traveling block  118 , a crown block (not shown), and a draw works  119  storing a support cable or line  123 . The crown block may be connected to or otherwise supported by the support structure  112 , and the traveling block  118  may be coupled with the top drive  116 , such as via a hook. The draw works  119  may be mounted on or otherwise supported by the rig floor  114 . The crown block and traveling block  118  comprise pulleys or sheaves around which the support line  123  is reeved to operatively connect the crown block, the traveling block  118 , and the draw works  119  (and perhaps an anchor). The draw works  119  may thus selectively impart tension to the support line  123  to lift and lower the top drive  116 , resulting in the vertical motion  135 . The draw works  119  may comprise a drum, a frame, and a prime mover (e.g., an engine or motor) (not shown) operable to drive the drum to rotate and reel in the support line  123 , causing the traveling block  118  and the top drive  116  to move upward. The draw works  119  may be operable to release the support line  123  via a controlled rotation of the drum, causing the traveling block  118  and the top drive  116  to move downward. 
     The top drive  116  may comprise a grabber, a swivel (neither shown), a tubular handling assembly links  127  terminating with an elevator  129 , and a drive shaft  125  operatively connected with a prime mover (not shown), such as via a gear box or transmission (not shown). The drill string  120  may be mechanically coupled to the drive shaft  125  with or without a sub saver between the drill string  120  and the drive shaft  125 . The prime mover may be selectively operated to rotate the drive shaft  125  and the drill string  120  coupled with the drive shaft  125 . Hence, during drilling operations, the top drive  116  in conjunction with operation of the draw works  119  may advance the drill string  120  into the formation  106  to form the wellbore  102 . The tubular handling assembly links  127  and the elevator  129  of the top drive  116  may handle tubulars (e.g., drill pipes, drill collars, casing joints, etc.) that are not mechanically coupled to the drive shaft  125 . For example, when the drill string  120  is being tripped into or out of the wellbore  102 , the elevator  129  may grasp the tubulars of the drill string  120  such that the tubulars may be raised and/or lowered via the hoisting equipment mechanically coupled to the top drive  116 . The grabber may include a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the drive shaft  125 . The top drive  116  may have a guide system (not shown), such as rollers that track up and down a guide rail on the support structure  112 . The guide system may aid in keeping the top drive  116  aligned with the wellbore  102 , and in preventing the top drive  116  from rotating during drilling by transferring reactive torque to the support structure  112 . 
     The well construction system  100  may further include a well control system for maintaining well pressure control. For example, the drill string  120  may be conveyed within the wellbore  102  through various blowout preventer (BOP) equipment disposed at the wellsite surface  104  on top of the wellbore  102  and perhaps below the rig floor  114 . The BOP equipment may be operable to control pressure within the wellbore  102  via a series of pressure barriers (e.g., rams) between the wellbore  102  and the wellsite surface  104 . The BOP equipment may include a BOP stack  130 , an annular preventer  132 , and/or a rotating control device (RCD)  138  mounted above the annular preventer  132 . The BOP equipment  130 ,  132 ,  138  may be mounted on top of a wellhead  134 . The well control system may further include a BOP control unit  137  (i.e., a BOP closing unit) operatively connected with the BOP equipment  130 ,  132 ,  138  and operable to actuate, drive, operate or otherwise control the BOP equipment  130 ,  132 ,  138 . The BOP control unit  137  may be or comprise a hydraulic fluid power unit fluidly connected with the BOP equipment  130 ,  132 ,  138  and selectively operable to hydraulically drive various portions (e.g., rams, valves, seals) of the BOP equipment  130 ,  132 ,  138 . 
     The well construction system  100  may further include a drilling fluid circulation system operable to circulate fluids between the surface equipment  110  and the drill bit  126  during drilling and other operations. For example, the drilling fluid circulation system may be operable to inject a drilling fluid from the wellsite surface  104  into the wellbore  102  via an internal fluid passage  121  extending longitudinally through the drill string  120 . The drilling fluid circulation system may comprise a pit, a tank, and/or other fluid container  142  holding the drilling fluid (i.e., mud)  140 , and a pump  144  operable to move the drilling fluid  140  from the container  142  into the fluid passage  121  of the drill string  120  via a fluid conduit  146  extending from the pump  144  to the top drive  116  and an internal passage extending through the top drive  116 . The fluid conduit  146  may comprise one or more of a pump discharge line, a stand pipe, a rotary hose, and a gooseneck (not shown) connected with a fluid inlet of the top drive  116 . The pump  144  and the container  142  may be fluidly connected by a fluid conduit  148 , such as a suction line. 
     During drilling operations, the drilling fluid may continue to flow downhole through the internal passage  121  of the drill string  120 , as indicated by directional arrow  158 . The drilling fluid may exit the BHA  124  via ports  128  in the drill bit  126  and then circulate uphole through an annular space  108  (“annulus”) of the wellbore  102  defined between an exterior of the drill string  120  and the wall of the wellbore  102 , such flow being indicated by directional arrows  159 . In this manner, the drilling fluid lubricates the drill bit  126  and carries formation cuttings uphole to the wellsite surface  104 . The returning drilling fluid may exit the annulus  108  via the RCD  138  and/or via a spool, a wing valve, a bell nipple, or another ported adapter  136 , which may be located below one or more portions of the BOP stack  130 . 
     The drilling fluid exiting the annulus  108  via the RCD  138  may be directed into a fluid conduit  160  (e.g., a drilling pressure control line), and may pass through various wellsite equipment fluidly connected along the conduit  160  prior to being returned to the container  142  for recirculation. For example, the drilling fluid may pass through a choke manifold  162  (e.g., a drilling pressure control choke manifold) connected along the conduit  160 . The choke manifold  162  may include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow through and out of the choke manifold  162 . Backpressure may be applied to the annulus  108  by variably restricting flow of the drilling fluid or other fluids flowing through the choke manifold  162 . The greater the restriction to flow through the choke manifold  162 , the greater the backpressure applied to the annulus  108 . 
     The drilling fluid may also or instead exit the annulus  108  via the ported adapter  136  and into a fluid conduit  171  (e.g., rig choke line), and may pass through various equipment fluidly connected along the conduit  171  prior to being returned to the container  142  for recirculation. For example, the drilling fluid may pass through a choke manifold  173  (e.g., a rig choke manifold) connected along the conduit  171 . The choke manifold  173  may include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow through the choke manifold  173 . Backpressure may be applied to the annulus  108  by variably restricting flow of the drilling fluid or other fluids flowing through the choke manifold  173 . 
     Before being returned to the container  142 , the drilling fluid returning to the wellsite surface  104  may be cleaned and/or reconditioned via drilling fluid reconditioning equipment  170 , which may include one or more of liquid gas separators, shale shakers, centrifuges, and other drilling fluid cleaning equipment. The liquid gas separators may remove formation gasses entrained in the drilling fluid discharged from the wellbore  102  and the shale shakers may separate and remove solid particles  141  (e.g., drill cuttings) from the drilling fluid. The drilling fluid reconditioning equipment  170  may further comprise equipment operable to remove additional gas and finer formation cuttings from the drilling fluid and/or modify physical properties or characteristics (e.g., rheology) of the drilling fluid. For example, the drilling fluid reconditioning equipment  170  may include a degasser, a desander, a desilter, a mud cleaner, and/or a decanter, among other examples. Intermediate tanks/containers (not shown) may be utilized to hold the drilling fluid while the drilling fluid progresses through the various stages or portions of the drilling fluid reconditioning equipment  170 . The cleaned/reconditioned drilling fluid may be transferred to the fluid container  142 , the solid particles  141  removed from the drilling fluid may be transferred to a solids container  143  (e.g., a reserve pit), and/or the removed gas may be transferred to a flare stack  172  via a conduit  174  (e.g., a flare line) to be burned or to a container (not shown) for storage and removal from the wellsite. 
     The surface equipment  110  may include tubular handling equipment operable to store, move, connect, and disconnect tubulars (e.g., drill pipes) to assemble and disassemble the conveyance means  122  of the drill string  120  during drilling operations. For example, a catwalk  131  may be utilized to convey tubulars from a ground level, such as along the wellsite surface  104 , to the rig floor  114 , permitting the tubular handling assembly links  127  to grab and lift the tubulars above the wellbore  102  for connection with previously deployed tubulars. The catwalk  131  may have a horizontal portion and an inclined portion that extends between the horizontal portion and the rig floor  114 . The catwalk  131  may comprise a skate  133  movable along a groove (not shown) extending longitudinally along the horizontal and inclined portions of the catwalk  131 . The skate  133  may be operable to convey (e.g., push) the tubulars along the catwalk  131  to the rig floor  114 . The skate  133  may be driven along the groove by a drive system (not shown), such as a pulley system or a hydraulic system. Additionally, one or more racks (not shown) may adjoin the horizontal portion of the catwalk  131 . The racks may have a spinner unit for transferring tubulars to the groove of the catwalk  131 . 
     An iron roughneck  151  may be positioned on the rig floor  114 . The iron roughneck  151  may comprise a torqueing portion  153 , such as may include a spinner and a torque wrench comprising a lower tong and an upper tong. The torqueing portion  153  of the iron roughneck  151  may be moveable toward and at least partially around the drill string  120 , such as may permit the iron roughneck  151  to make up and break out connections of the drill string  120 . The torqueing portion  153  may also be moveable away from the drill string  120 , such as may permit the iron roughneck  151  to move clear of the drill string  120  during drilling operations. The spinner of the iron roughneck  151  may be utilized to apply low torque to make up and break out threaded connections between tubulars of the drill string  120 , and the torque wrench may be utilized to apply a higher torque to tighten and loosen the threaded connections. 
     Reciprocating slips  161  may be located on the rig floor  114 , such as may accommodate therethrough the downhole tubulars during make up and break out operations and during the drilling operations. The reciprocating slips  161  may be in an open position during drilling operations to permit advancement of the drill string  120  therethrough, and in a closed position to clamp an upper end of the conveyance means  122  (e.g., assembled tubulars) to thereby suspend and prevent advancement of the drill string  120  within the wellbore  102 , such as during the make up and break out operations. 
     During drilling operations, the hoisting equipment lowers the drill string  120  while the top drive  116  rotates the drill string  120  to advance the drill string  120  downward within the wellbore  102  and into the formation  106 . During the advancement of the drill string  120 , the reciprocating slips  161  are in an open position, and the iron roughneck  151  is moved away or is otherwise clear of the drill string  120 . When the upper portion of the tubular in the drill string  120  that is made up to the drive shaft  125  is near the reciprocating slips  161  and/or the rig floor  114 , the top drive  116  ceases rotating and the reciprocating slips  161  close to clamp the tubular made up to the drive shaft  125 . The grabber of the top drive  116  then clamps the upper portion of the tubular made up to the drive shaft  125 , and the drive shaft  125  rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft  125  and the made up tubular. The grabber of the top drive  116  may then release the tubular of the drill string  120 . 
     Multiple tubulars may be loaded on the rack of the catwalk  131  and individual tubulars (or stands of two or three tubulars) may be transferred from the rack to the groove in the catwalk  131 , such as by the spinner unit. The tubular positioned in the groove may be conveyed along the groove by the skate  133  until an end of the tubular projects above the rig floor  114 . The elevator  129  of the top drive  116  then grasps the protruding end, and the draw works  119  is operated to lift the top drive  116 , the elevator  129 , and the new tubular. 
     The hoisting equipment then raises the top drive  116 , the elevator  129 , and the tubular until the tubular is aligned with the upper portion of the drill string  120  clamped by the slips  161 . The iron roughneck  151  is moved toward the drill string  120 , and the lower tong of the torqueing portion  153  clamps onto the upper portion of the drill string  120 . The spinning system rotates the new tubular (e.g., a threaded male end) into the upper portion of the drill string  120  (e.g., a threaded female end). The upper tong then clamps onto the new tubular and rotates with high torque to complete making up the connection with the drill string  120 . In this manner, the new tubular becomes part of the drill string  120 . The iron roughneck  151  then releases and moves clear of the drill string  120 . 
     The grabber of the top drive  116  may then clamp onto the drill string  120 . The drive shaft  125  (e.g., a threaded male end) is brought into contact with the drill string  120  (e.g., a threaded female end) and rotated to make up a connection between the drill string  120  and the drive shaft  125 . The grabber then releases the drill string  120 , and the reciprocating slips  161  are moved to the open position. The drilling operations may then resume. 
     The tubular handling equipment may further include a pipe handling manipulator (PHM)  163  disposed in association with a fingerboard  165 . Although the PHM  163  and the fingerboard  165  are shown supported on the rig floor  114 , one or both of the PHM  163  and fingerboard  165  may be located on the wellsite surface  104  or another area of the well construction system  100 . The fingerboard  165  provides storage (e.g., temporary storage) of tubulars (or stands of two or three tubulars)  111  during various operations, such as during and between tripping out and tripping in the drill string  120 . The PHM  163  may be operable to transfer the tubulars  111  between the fingerboard  165  and the drill string  120  (i.e., space above the suspended drill string  120 ). For example, the PHM  163  may include arms  167  terminating with clamps  169 , such as may be operable to grasp and/or clamp onto one of the tubulars  111 . The arms  167  of the PHM  163  may extend and retract, and/or at least a portion of the PHM  163  may be rotatable and/or movable toward and away from the drill string  120 , such as may permit the PHM  163  to transfer the tubular  111  between the fingerboard  165  and the drill string  120 . 
     To trip out the drill string  120 , the top drive  116  is raised, the reciprocating slips  161  are closed around the drill string  120 , and the elevator  129  is closed around the drill string  120 . The grabber of the top drive  116  clamps the upper portion of the tubular made up to the drive shaft  125 . The drive shaft  125  then rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft  125  and the drill string  120 . The grabber of the top drive  116  then releases the tubular of the drill string  120 , and the drill string  120  is suspended by (at least in part) the elevator  129 . The iron roughneck  151  is moved toward the drill string  120 . The lower tong clamps onto a lower tubular below a connection of the drill string  120 , and the upper tong clamps onto an upper tubular above that connection. The upper tong then rotates the upper tubular to provide a high torque to break out the connection between the upper and lower tubulars. The spinning system then rotates the upper tubular to separate the upper and lower tubulars, such that the upper tubular is suspended above the rig floor  114  by the elevator  129 . The iron roughneck  151  then releases the drill string  120  and moves clear of the drill string  120 . 
     The PHM  163  may then move toward the drill string  120  to grasp the tubular suspended from the elevator  129 . The elevator  129  then opens to release the tubular. The PHM  163  then moves away from the drill string  120  while grasping the tubular with the clamps  169 , places the tubular in the fingerboard  165 , and releases the tubular for storage in the fingerboard  165 . This process is repeated until the intended length of drill string  120  is removed from the wellbore  102 . 
     The surface equipment  110  of the well construction system  100  may also comprise a control center  190  from which various portions of the well construction system  100 , such as the top drive  116 , the hoisting system, the tubular handling system, the drilling fluid circulation system, the well control system, the BHA  124 , among other examples, may be monitored and controlled. The control center  190  may be located on the rig floor  114  or another location of the well construction system  100 , such as the wellsite surface  104 . The control center  190  may comprise a facility  191  (e.g., a room, a cabin, a trailer, etc.) containing a control workstation  197 , which may be operated by a human wellsite operator  195  to monitor and control various wellsite equipment or portions of the well construction system  100 . The control workstation  197  may comprise or be communicatively connected with a processing device  192  (e.g., a controller, a computer, etc.), such as may be operable to receive, process, and output information to monitor operations of and provide control to one or more portions of the well construction system  100 . For example, the processing device  192  may be communicatively connected with the various surface and downhole equipment described herein, and may be operable to receive signals from and transmit signals to such equipment to perform various operations described herein. The processing device  192  may store executable program code, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of methods and operations described herein. The processing device  192  may be located within and/or outside of the facility  191 . 
     The control workstation  197  may be operable for entering or otherwise communicating control commands to the processing device  192  by the wellsite operator  195 , and for displaying or otherwise communicating information from the processing device  192  to the wellsite operator  195 . The control workstation  197  may comprise a plurality of human-machine interface (HMI) devices, including one or more input devices  194  (e.g., a keyboard, a mouse, a joystick, a touchscreen, etc.) and one or more output devices  196  (e.g., a video monitor, a touchscreen, a printer, audio speakers, etc.). Communication between the processing device  192 , the input and output devices  194 ,  196 , and the various wellsite equipment may be via wired and/or wireless communication means. However, for clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure. 
     Well construction systems within the scope of the present disclosure may include more or fewer components than as described above and depicted in  FIG. 1 . Additionally, various equipment and/or subsystems of the well construction system  100  shown in  FIG. 1  may include more or fewer components than as described above and depicted in  FIG. 1 . For example, various engines, motors, hydraulics, actuators, valves, and/or other components not explicitly described herein may be included in the well construction system  100 , and are within the scope of the present disclosure. 
     The well construction system  100  also includes stationary and/or mobile video cameras  198  disposed or utilized at various locations within the well construction system  100 . The video cameras  198  capture videos of various portions, equipment, or subsystems of the well construction system  100 , and perhaps the wellsite operators  195  and the actions they perform, during or otherwise in association with the wellsite operations, including while performing repairs to the well construction system  100  during a breakdown. For example, the video cameras  198  may capture digital images (or video frames) of the entire well construction system  100  and/or specific portions of the well construction system  100 , such as the top drive  116 , the iron roughneck  151 , the PHM  163 , the fingerboard  165 , and/or the catwalk  131 , among other examples. The video cameras  198  generate corresponding video signals (i.e., feeds) comprising or otherwise indicative of the captured digital images. The video cameras  198  may be in signal communication with the processing device  192 , such as may permit the video signals to be processed and transmitted to the control workstation  197  and, thus, permit the wellsite operators  195  to view various portions or components of the well construction system  100  on one or more of the output devices  196 . The processing device  192  or another portion of the control workstation  197  may be operable to record the video signals generated by the video cameras  198 . 
     The present disclosure further provides various implementations of systems and/or methods for controlling one or more portions of the well construction system  100 .  FIG. 2  is a schematic view of at least a portion of an example implementation of a monitoring and control system  200  for monitoring and controlling various equipment, portions, and subsystems of the well construction system  100  according to one or more aspects of the present disclosure. The following description refers to  FIGS. 1 and 2 , collectively. 
     The control system  200  may be in real-time communication with and utilized to monitor and/or control various portions, components, and equipment of the well construction system  100  described herein. The equipment of the well construction system  100  may be grouped into several subsystems, each operable to perform a corresponding operation and/or a portion of the well construction operations described herein. The subsystems may include a rig control (RC) system  211 , a fluid circulation (FC) system  212 , a managed pressure drilling control (MPDC) system  213 , a choke pressure control (CPC) system  214 , a well pressure control (WC) system  215 , and a closed-circuit television (CCTV) system  216 . The control workstation  197  may be utilized to monitor, configure, control, and/or otherwise operate one or more of the well construction subsystems  211 - 216 . 
     The RC system  211  may include the support structure  112 , the drill string hoisting system or equipment (e.g., the draw works  119  and the top drive  116 ), drill string drivers (e.g., the top drive  116  and/or the rotary table and kelly), the reciprocating slips  161 , the drill pipe handling system or equipment (e.g., the catwalk  131 , the PHM  163 , the fingerboard  165 , and the iron roughneck  151 ), electrical generators, and other equipment. Accordingly, the RC system  211  may perform power generation and drill pipe handling, hoisting, and rotation operations. The RC system  211  may also serve as a support platform for drilling equipment and staging ground for rig operations, such as connection make up and break out operations described above. The FC system  212  may include the drilling fluid  140 , the pumps  144 , drilling fluid loading equipment, the drilling fluid reconditioning equipment  170 , the flare stack  172 , and/or other fluid control equipment. Accordingly, the FC system  212  may perform fluid operations of the well construction system  100 . The MPDC system  213  may include the RCD  138 , the choke manifold  162 , downhole pressure sensors  186 , and/or other equipment. The CPC system  214  may comprise the choke manifold  173 , and/or other equipment, and the WC system  215  may comprise the BOP equipment  130 ,  132 ,  138 , the BOP control unit  137 , and a BOP control station (not shown) for controlling the BOP control unit  137 . The CCTV system  216  may include the video cameras  198  and corresponding actuators (e.g., motors) for moving or otherwise controlling direction of the video cameras  198 . The CCTV system  216  may be utilized to capture real-time video of various portions or subsystems  211 - 215  of the well construction system  100  and display video signals from the video cameras  198  on the video output devices  196  to display in real-time the various portions or subsystems  211 - 215 . Each of the well construction subsystems  211 - 216  may further comprise various communication equipment (e.g., modems, network interface cards, etc.) and communication conductors (e.g., cables), communicatively connecting the equipment (e.g., sensors and actuators) of each subsystem  211 - 216  with the control workstation  197  and/or other equipment. Although the wellsite equipment listed above and shown in  FIG. 1  is associated with certain wellsite subsystems  211 - 216 , such associations are merely examples that are not intended to limit or prevent such wellsite equipment from being associated with two or more wellsite subsystems  211 - 216  and/or different wellsite subsystems  211 - 216 . 
     The control system  200  may also include various local controllers  221 - 226  associated with corresponding subsystems  211 - 216  and/or individual pieces of equipment of the well construction system  100 . As described above, each well construction subsystem  211 - 216  includes various wellsite equipment comprising corresponding actuators  241 - 246  for performing operations of the well construction system  100 . Each subsystem  211 - 216  further includes various sensors  231 - 236  operable to generate sensor data indicative of operational performance and/or status of the wellsite equipment of each subsystem  211 - 216 . Although the sensors  231 - 236  and actuators  241 - 246  are each shown as a single block, it is to be understood that each sensor  231 - 236  and actuator  241 - 246  may be or comprise a plurality of sensors and actuators, whereby each actuator performs a corresponding action of a piece of equipment or subsystem  211 - 216  and each sensor generates corresponding sensor data indicative of the action performed by a corresponding actuator or of other operational parameter of the piece of equipment or subsystem  211 - 216 . 
     The local controllers  221 - 226 , the sensors  231 - 236 , and the actuators  241 - 246  may be communicatively connected with a processing device  202 . For example, the local controllers may be in communication with the sensors  231 - 236  and actuators  241 - 246  of the corresponding subsystems  211 - 216  via local communication networks (e.g., field buses, not shown) and the processing device  202  may be in communication with the subsystems  211 - 216  via a communication network  209  (e.g., data bus, a wide-area-network (WAN), a local-area-network (LAN), etc.). The sensor data (e.g., electronic signals, information, and/or measurements, etc.) generated by the sensors  231 - 236  of the subsystems  211 - 216  may be made available for use by processing device  202  and/or the local controllers  221 - 226 . Similarly, control commands (e.g., signals, information, etc.) generated by the processing device  202  and/or the local controllers  221 - 226  may be automatically communicated to the various actuators  241 - 246  of the subsystems  211 - 216 , perhaps pursuant to predetermined programming, such as to facilitate well construction operations and/or other operations described herein. The processing device  202  may be or comprise the processing device  192  shown in  FIG. 1 . Accordingly, the processing device  202  may be communicatively connected with or form a portion of the workstation  197  and/or may be at least partially located within the control center  190 . 
     The sensors  231 - 236  and actuators  241 - 246  may be monitored and/or controlled by the processing device  202 . For example, the processing device  202  may be operable to receive the sensor data from the sensors  231 - 236  of the wellsite subsystems  211 - 216  in real-time, and to provide real-time control commands to the actuators  241 - 246  of the subsystems  211 - 216  based on the received sensor data. However, certain operations of the actuators  241 - 246  may be controlled by the local controllers  221 - 226 , which may control the actuators  241 - 246  based on sensor data received from the sensors  231 - 236  and/or based on control commands received from the processing device  202 . 
     The processing devices  188 ,  192 ,  202 , the local controllers  221 - 226 , and other controllers or processing devices of the well construction system  100  may be operable to receive program code instructions and/or sensor data from sensors (e.g., sensors  231 - 236 ), process such information, and/or generate control commands to operate controllable equipment (e.g., actuators  241 - 246 ) of the well construction system  100 . Accordingly, the processing devices  188 ,  192 ,  202 , the local controllers  221 - 226 , and other controllers or processing devices of the well construction system  100  may individually or collectively be referred to hereinafter as equipment controllers. Equipment controllers within the scope of the present disclosure can include, for example, programmable logic controllers (PLCs), industrial computers (IPCs), personal computers (PCs), soft PLCs, variable frequency drives (VFDs) and/or other controllers or processing devices operable to receive sensor data and/or control commands and cause operation of controllable equipment based on such sensor data and/or control commands. 
     The various pieces of wellsite equipment described above and shown in  FIGS. 1 and 2  may each comprise one or more hydraulic and/or electrical actuators, which when actuated, may cause corresponding components or portions of the piece of equipment to perform intended actions (e.g., work, tasks, movements, operations, etc.). Each piece of equipment may further comprise a plurality of sensors, whereby one or more sensors may be associated with a corresponding actuator or another component of the piece of equipment and communicatively connected with an equipment controller. Each sensor may be operable to generate sensor data (e.g., electrical sensor signals or measurements) indicative of an operational (e.g., mechanical, physical) status of the corresponding actuator or component, thereby permitting the operational status of the actuator to be monitored by the equipment controller. The sensor data may be utilized by the equipment controller as feedback data, permitting operational control of the piece of equipment and coordination with other equipment. Such sensor data may be indicative of performance of each individual actuator and, collectively, of the entire piece of wellsite equipment. 
     The present disclosure is further directed to performance based condition monitoring, which utilizes sensor data indicative of actions performed or otherwise caused by actuators of a piece of wellsite equipment to generate performance based condition indicators, which in turn, may be utilized as a basis for determining condition (e.g., operational health, operational life, maintenance condition, etc.) of the piece of wellsite equipment. Performance based condition indicators may be indicative of condition of each actuator and/or other components facilitating each action performed by the piece of equipment. Performance based condition indicators may be utilized as a basis for predicting developing faults (i.e., operational problems, breakdowns, failures) before such faults have manifested themselves through visual and/or physical detection by a wellsite operator or a full stop (i.e., failure) of the wellsite equipment. When a fault has progressed to a point at which it is detectable via audible noise or excessive temperature (e.g., too hot to touch), the equipment is approaching point of failure. 
     Performance based condition monitoring according to one or more aspects of the present disclosure utilizes a bottom-up approach, which focuses on sensor data indicative of detailed operational parameters (e.g., physical states) of individual actuators or other components causing or otherwise associated with each action performed by a piece of equipment. The sensor data may then be utilized to predict or determine the condition of the piece of wellsite equipment. For example, the performance based condition monitoring may include recording sensor data for each sensor, actuator, and/or action of a piece of equipment, and analyzing or otherwise processing such sensor data to generate performance based condition indicators to predict or determine condition of the piece of equipment. Performance based condition indicators may be calculated or otherwise generated based on sensor data indicative of physical states during each action caused, performed, or otherwise facilitated by a corresponding actuator or another part of a piece of wellsite equipment. Performance based condition monitoring according to one or more aspects of the present disclosure may also consolidate the sensor data by generating the performance based condition indicators associated with a piece of wellsite equipment. 
     Performance based condition indicators may also be determined based on additional condition monitoring data indicative of other operational parameters, factors, conditions, characteristics, and descriptions related to a piece of wellsite equipment and the operations such wellsite equipment performs.  FIG. 3  is a flow-chart diagram showing an example implementation of a performance based condition monitoring process  300  according to one or more aspects of the present disclosure. 
     The condition monitoring data may include sensor data  302 , control commands  304 , process description data  306 , process variance data  308 , and process contextual data  310 . As described above, sensor data  302  may be indicative of physical states of an actuator or another component of a piece of equipment during an action that was caused, performed, or otherwise facilitated by the actuator or another component. The sensor data may be indicative of different points of measurement of the action performed. The sensor data may include, for example, position of a hydraulic cylinder or motor, hydraulic fluid pressure, pressure within an accumulator, flow generated by a pump, force generated by an actuator, and temperature of hydraulic fluid. 
     Performance based condition indicators may also be calculated based on control commands (e.g., control signals, sequence steps, control functions, etc.) generated or outputted by equipment controllers to the individual actuators of the wellsite equipment triggering or causing the intended actions. Use of control commands highlights performance of the actuators in the overall process efficiency, thereby treating the actuator performance independently of operator or process parameters. The sensor signals may be compared to the control commands to determine differences in performance between an action that was intended, as indicated by the control commend, and an action that was actually executed, as indicated by the sensor signal. Control commands may initiate the action. Control commands may include, for example, control signals that are transmitted by an equipment controller (e.g., processing devices  192 ,  202  and local controllers  221 - 226  shown in  FIGS. 1 and 2 ) to a mechanical controller, such as a hydraulic valve, to operate a hydraulic actuator, or an electrical controller, such as a relay or VFD, to operate an electrical actuator. Process description data  306  may be descriptive or otherwise indicative of an individual action performed by a piece of wellsite equipment and defined by the sensor data. Process description data  306  may include, for example, extension of a top drive dolly, charging of hydraulic accumulators, rotation of a draw works drum, and extension of racker main arm. Process variance data  308  may be indicative of changed conditions or other factors associated with a piece of equipment that can influence or skew the sensor data while an action is performed. Process variance data  308  may be indicative of, for example, weight of a gripper head, cylinder pressure, hydraulic fluid supply pressure, hydraulic fluid temperature, ambient temperature, speed reference, position reference, equipment controller deviation, and control joystick position. Process contextual data  310  may be or comprise factors that can cause the sensor data associated with an action to be inaccurate. Process contextual data  310  may be or comprise, for example, automatic sequence step, operational mode, trolley position, pipe data, slew position, main arm vertical position, hydraulic position deviation, weight cell reference, weight cell deviation, tubular interlock messages, zone management messages, operation messages, warnings, and alarms. 
     As further shown in  FIG. 3 , the condition monitoring data  302 ,  304 ,  306 ,  308 ,  310  may be received and processed by a processing device  312 , which may generate performance based condition indicators  314  based on the condition monitoring data. During operations of a piece of equipment, control commands  304  may be transmitted from an equipment controller to a mechanical/electrical controller to operate an actuator, thereby triggering or initiating an action. While the action is performed, the control commands  304  and the sensor data  302  may be received by the processing device  312 . The process description data  306 , the process variance data  308 , and process contextual data  310  may also be received by the processing device  312  while the action is performed. The condition monitoring data  306 ,  308 ,  310  may be generated by and equipment controller operating the piece of equipment, other sensors associated with the piece of equipment, and/or from wellsite operators. The process variance data  308  may be indicative of changed conditions or other factors that can influence the actions performed by the piece of equipment and, thereby, skew, shift, introduce noise, or otherwise change the sensor data  302 . Accordingly, process variance data  308  may be utilized by the processing device  312  to shift sensor data  302  that was changed by the process variance data  308  to compensate for the changes in the sensor data  302 . Process contextual data  310  may be indicative of, for example, a change of state or condition of the piece of equipment that renders sensor data  302  invalid. Process contextual data  310  may, thus, be utilized by the processing device  312  to invalidate certain sensor data  302  that may be affected by the state or condition of the piece of equipment. Accordingly, validated sensor data  302  may be processed by the processing device  312  to generate (e.g., calculate) the performance based condition indicators  314 , and invalidated sensor data  302  may not be utilized (e.g., may be disregarded) by the processing device  312  as a basis for generating the performance based condition indicators  314 . Example performance based condition indicators  314  generated by the processing device  312  may comprise, for example, travel time, acceleration, mean velocity, maximum velocity, control command deviation (variance), control command deviation (amplitude), utilization spectrum, and exposure spectrum, among other examples. 
     The condition monitoring data  302 ,  304 ,  306 ,  308 ,  310  may be generated in real-time at high sampling rates and, thus, be or comprise high resolution data  316  using a high bandwidth data transmission and/or processing. The performance based condition indicators  314  generated by the processing device  312  is or comprises a single measurement, as opposed to five measurements that include the condition monitoring data  302 ,  304 ,  306 ,  308 ,  310 . Furthermore, the performance based condition indicators  314  may be calculated by the processing device  312  at lower frequencies than the sampling rates of the condition monitoring data  302 ,  304 ,  306 ,  308 ,  310 . The performance based condition indicators  314  may, thus, be or comprise condensed (lower resolution) data  318 , permitting low bandwidth data transmission and/or processing. 
     The performance based condition indicators  314  may be transmitted to and stored in a historian  320  (e.g., database, data storage center). The historian  320  may be located at the wellsite or at a location remote from the wellsite. Current and historical performance based condition indicators  314  may be analyzed systematically or in real-time over a period of time by the processing device  312  at the wellsite or another processing device  322  located remotely from the wellsite. The processing device  312  and/or processing device  322  may process the current and historical performance based condition indicators  314  to recognize changes or trends in performance (e.g., performance quality degradation) of individual actuators or components. Such trends may be indicative of developing or potential faults, which may be repaired or otherwise addressed before failure or large reductions in performance can manifest. When at least one of the performance based condition indicators  314  falls below a predetermined threshold, the processing device  312  and/or processing device  322  may then generate or output condition information  324  indicative of health of the piece of equipment. The processing device  312  and/or processing device  322  may comprise or store computer program code, which when executed by the processing devices  312 ,  322  may generate, calculate, or output the performance based condition indicators  314  and/or the condition information  324  based on the performance based condition indicators  314 . The computer program code may be or comprise modeling or predictive processes, engines, algorithms, applications, and/or other programs operable to predict or determine condition of a piece of equipment and/or one or more of its components. 
       FIGS. 4 and 5  are flow-chart diagrams showing example implementations of processes  340 ,  370  according to one or more aspects of the present disclosure. The process  340  shown in  FIG. 4  may comprise generating the high resolution condition monitoring data  342  at a drill rig  344  and transmitting  345  such data  342  in real-time via a high bandwidth data pipeline  346  to a processing device  348  located at a remote (e.g., distant) location  350  from the drill rig  344 . The data  342  may comprise, for example, the condition monitoring data  302 ,  304 ,  306 ,  308 ,  310  described above and shown in  FIG. 3 . The remote location  350  may be or comprise an offsite data center and/or server. As shown, the process  340  utilizes the high bandwidth data pipeline  346  to transmit the high resolution input data  342  in real-time over a long distance to the processing device  348 , which may process the data  342  to generate or output  352  performance based condition indicators  354  and, thus, condense the data  342  at the remote location  350 . The performance based condition indicators  354  may then be fed  356  to and processed by a processing device  358  comprising modeling or predictive processes, engines, algorithms, applications and/or other computer programs, which may determine and output  360  condition information  362  indicative of the condition of the piece of equipment and/or one or more of its components at the drill rig  344 . The performance based condition indicators  354  may be saved in a database (such the historian  320  shown in  FIG. 3 ) and accessed by the processing device  358 . The processing device  358  may be operable to analyze current and historical performance based condition indicators  354  systematically or in real-time over a period of time, such as to recognize changes or trends in performance (e.g., execution) of actions caused by individual actuators or components. The recognized changes or trends may be indicative of developing or potential faults, which may be repaired or otherwise addressed before failure or large reductions in performance can manifest. Because both processing devices  348 ,  358  are located at the remote location  350 , the performance based condition indicators  354  and the condition information  362  may be generated or outputted by single processing device. 
     The process  370  shown in  FIG. 5  may comprise features of the process  340  shown in  FIG. 4 , including where indicated by the same numerals. The process  370  may comprise generating the high resolution condition monitoring data  342  at a drill rig  344  and feeding  372  such data  342  to the processing device  348 , which may process the data  342  to generate or output  352  performance based condition indicators  354  and, thus, condense the data  342  at the drill rig  344 . The condensed performance based condition indicators  354  may then be transmitted  374  in real-time via a low bandwidth data pipeline  376  to a processing device  358  located at a remote location  350  from the drill rig  344 . The performance based condition indicators  354  may then be fed to and processed by a processing device  358  comprising modeling or predictive processes, engines, algorithms, applications and/or other computer programs, which may determine and output  360  condition information  362  indicative of the condition of the piece of equipment and/or one or more of its components at the remote location  350 . Generating the condensed performance based condition indicators  354  at the drill rig  344  facilitates a reduction in data that has to be transmitted to the remote location  350 , thereby reducing bandwidth prerequisites between the rig  344  and the remote location  350 . Reduced bandwidth use may, in turn, reduce transmission interruptions and/or loss of transmitted data. 
       FIG. 6  shows a schematic view of an example implementation of a monitoring and control system  400  for monitoring and controlling a piece of equipment  402  according to one or more aspects of the present disclosure. The control system  400  may be or comprise a portion of a well construction system, such as the well construction system  100  shown in  FIG. 1 . The piece of equipment  402  may be or comprise a piece of wellsite equipment of a well construction system, such as the well construction system  100  shown in  FIG. 1 . For example, the piece of equipment  402  may be or comprise a top drive  116 , a draw works  119 , an iron roughneck  151 , a PHM  163 , a catwalk  131 , a mud pump  144 , a BOP control unit  137 , a portion of the fluid reconditioning equipment  170 , or another piece of pipe handling equipment. 
     The piece of equipment  402  may comprise a plurality of actuators  406 , each operable to actuate a corresponding member, part, or component  408  of the piece of equipment  402  to perform a corresponding action (e.g., work, operation, task, process, etc.). The actuators  406  may be or comprise hydraulic cylinders, hydraulic motors, and/or electrical motors, among other examples. The components  408  may be or comprise arms, grippers, brackets, dollies, trolleys, drums, and wheels, among other examples. The piece of equipment  402  may further comprise a plurality of mechanical and/or electrical controllers  410 , each selectively operable to power or otherwise operate a corresponding actuator  406  to perform an action via a corresponding component  408 . The mechanical controllers  410  may be or comprise hydraulic valves and pneumatic valves, among other examples, and the electrical controllers  410  may be or comprise electrical relays and VFDs, among other examples. The piece of equipment  402  may further comprise a plurality of sensors  412 , each disposed in association with a corresponding actuator  406  and/or component  408 , and operable to generate sensor data (e.g., sensor signals, measurements) indicative of physical status (i.e., operational status) caused by the corresponding actuator  406  and/or experienced by the component  408 . The sensors  412  may be or comprise position sensors (e.g., encoders, rotary potentiometers, linear potentiometers, synchros, resolvers, proximity sensors, Hall effect sensors, and/or rotary variable-differential transformers (RVDTs)), pressure sensors, temperature sensors, and force sensors (e.g., load cells), among other examples. 
     The mechanical and/or electrical controllers  410  and the sensors  412  may be communicatively connected with an equipment controller  404 , thereby permitting the equipment controller  414  to receive and process the sensor data, and transmit control commands (i.e., control signals) based on the sensor data to the mechanical and/or electrical controllers  410  to cause the actuators  406  to perform the intended actions. The equipment controller  404  may be a local or direct controller (e.g., a PLC) associated with the piece of equipment  402 . The equipment controller  404  may be communicatively connected to another equipment controller  414 , which may be or comprise a coordinated controller (e.g., PC, IPC) operable to store execute machine-readable and executable program code instructions (i.e., computer program code  416 ) in a memory device of the equipment controller  414 . The equipment controller  414  may be located at a remote location from the equipment  402  and/or the equipment controller  404 . 
     The computer program code  416  may comprise a performance based condition monitoring application (PBCMA)  418 , which when executed, may be operable to receive from the equipment controller  404  the sensor data generated by the sensors  412 . The performance based condition monitoring application  418  may also receive control commands, process description data, process variance data, and process contextual data generated, outputted, and/or utilized by at least one of the equipment controllers  404 ,  414  and/or other sensors associated with the piece of equipment. The performance based condition monitoring application  418  may comprise various mathematical algorithms, mathematical functions, logical functions, and other machine functions, such as may comprise mathematical and logical calculations with inputs and outputs. The performance based condition monitoring application  418 , which when executed, may be further operable to process the input data and generate performance based condition indicators indicative of condition of the piece of equipment  402  based on the input data. 
     The performance based condition indicators may be stored by the equipment controller  414  or on an external memory device  420 . Current and historical performance based condition indicators may be analyzed systematically or in real-time over a period of time by the performance based condition monitoring application  418  to recognize changes or trends in performance of the individual actuators  406  and/or components  408 . Such trends may be indicative of developing or potential faults, which may be repaired or otherwise addressed before failure or large reductions in performance can manifest. When the performance based condition indicators fall below a predetermined performance threshold, the equipment controller  414  may generate or output condition information indicative of health of the piece of equipment to a wellsite operator via an output device. 
       FIG. 7  is a schematic view of at least a portion of an example implementation of a processing system  500  (or device) according to one or more aspects of the present disclosure. The processing system  500  may be or form at least a portion of one or more equipment controllers and/or other processing systems shown in one or more of the  FIGS. 1-6 . Accordingly, the following description refers to  FIGS. 1-7 , collectively. 
     The processing system  500  may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, PCs (e.g., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, IPCs, PLCs, servers, internet appliances, and/or other types of computing devices. The processing system  500  may be or form at least a portion of the processing devices  192 ,  202 ,  312 ,  322 ,  348 ,  358  and/or equipment controllers  221 - 226 ,  404 ,  414 . Although it is possible that the entirety of the processing system  500  is implemented within one device, it is also contemplated that one or more components or functions of the processing system  500  may be implemented across multiple devices, some or an entirety of which may be at the wellsite and/or remote from the wellsite. 
     The processing system  500  may comprise a processor  512 , such as a general-purpose programmable processor. The processor  512  may comprise a local memory  514 , and may execute machine-readable and executable program code instructions  532  (i.e., computer program code) present in the local memory  514  and/or another memory device. The processor  512  may execute, among other things, the program code instructions  532  and/or other instructions and/or programs to implement the example methods, processes, and/or operations described herein. The program code instructions  532  stored in the local memory  514 , when executed by the processor  512  of the processing system  500 , may cause one or more portions or pieces of wellsite equipment of a well construction system to perform the example methods and/or operations described herein. The processor  512  may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Examples of the processor  512  include one or more INTEL microprocessors, microcontrollers from the ARM and/or PICO families of microcontrollers, embedded soft/hard processors in one or more FPGAs. 
     The processor  512  may be in communication with a main memory  516 , such as may include a volatile memory  518  and a non-volatile memory  520 , perhaps via a bus  522  and/or other communication means. The volatile memory  518  may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory  520  may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory  518  and/or non-volatile memory  520 . 
     The processing system  500  may also comprise an interface circuit  524 , which is in communication with the processor  512 , such as via the bus  522 . The interface circuit  524  may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others. The interface circuit  524  may comprise a graphics driver card. The interface circuit  524  may comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.). 
     The processing system  500  may be in communication with various video cameras, sensors, actuators, equipment controllers, and other devices of the well construction system via the interface circuit  524 . The interface circuit  524  can facilitate communications between the processing system  500  and one or more devices by utilizing one or more communication protocols, such as an Ethernet-based network protocol (such as ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 communication, or the like), a proprietary communication protocol, and/or another communication protocol. 
     One or more input devices  526  may also be connected to the interface circuit  524 . The input devices  526  may permit human wellsite operators  195  to enter the program code instructions  532 , which may be or comprise control commands, operational parameters, and/or operational set-points. The program code instructions  532  may further comprise modeling or predictive routines, equations, algorithms, processes, engines, algorithms, applications (e.g., a performance based condition monitoring application), and/or other programs operable to calculate performance based condition indicators and predict or determine condition of a piece of equipment and/or one or more of its components based on the performance based condition indicators, as described herein. The input devices  526  may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples. One or more output devices  528  may also be connected to the interface circuit  524 . The output devices  528  may permit for visualization or other sensory perception of various data, such as sensor data, status data, and/or other example data. The output devices  528  may be, comprise, or be implemented by video output devices (e.g., an LCD, an LED display, a CRT display, a touchscreen, etc.), printers, and/or speakers, among other examples. The one or more input devices  526  and the one or more output devices  528  connected to the interface circuit  524  may, at least in part, facilitate the HMIs described herein. 
     The processing system  500  may comprise a mass storage device  530  for storing data and program code instructions  532 . The mass storage device  530  may be connected to the processor  512 , such as via the bus  522 . The mass storage device  530  may be or comprise a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples. The processing system  500  may be communicatively connected with an external storage medium  534  via the interface circuit  524 . The external storage medium  534  may be or comprise a removable storage medium (e.g., a CD or DVD), such as may be operable to store data and program code instructions  532 . 
     As described above, the program code instructions  532  may be stored in the mass storage device  530 , the main memory  516 , the local memory  514 , and/or the removable storage medium  534 . Thus, the processing system  500  may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor  512 . In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code instructions  532  (i.e., software or firmware) thereon for execution by the processor  512 . The program code instructions  532  may include program instructions or computer program code that, when executed by the processor  512 , may cause one or more portions of the well construction system  100  to perform intended methods, processes, and/or operations disclosed herein. 
       FIG. 8  is a graph  610  showing a single performance based condition indicator, namely a position profile  612  of a component of a piece of wellsite equipment while performing an action. The profile  612  shows the relationship between position of the component, plotted along the vertical axis, and time, plotted along the horizontal axis. The profile  612  may be determined by a processing device, such as the processing system  500 , based on sensor data generated by a position sensor associated with the component. The horizontal axis may be indicative of the starting position of the component, and a horizontal reference line  614  may be indicative of the final position. Furthermore, the vertical axis may be indicative of the starting (i.e., trigger) time of the action performed by the component, and a vertical reference line  616  may be indicative of the time  618  at which the action is completed. The amount of time  618  for the action to be completed (e.g., travel time, cycle time) may be calculated and saved by the processing device as a single instance (i.e., sample) of a performance based condition indicator. The graph  610  further shows an intended position profile  622  of the component while performing the action. The profile  622  shows the relationship between an intended position of the component, plotted along the vertical axis, and time, plotted along the horizontal axis. The profile  612  may be determined by the processing device based on control commands (i.e., control signals) generated by an equipment controller for controlling the piece of equipment. The vertical axis may be indicative of the starting time of the action performed by the component, and a vertical reference line  624  may be indicative of the time  626  at which the control command intended to complete the action. The lag time  628  (i.e., controller deviation) between the actual  618  and intended  626  completion times of the action may be calculated and saved by the processing device as a single instance of a performance based condition indicator in addition to or instead of the amount of time  618  for the action to be completed. 
       FIG. 9  is a graph  640  showing a plurality performance based condition indicators  642 , namely cycle (i.e., travel) times  642  of a component of a piece of wellsite equipment recorded over time. The graph  640  shows that the cycle times  642  are progressively increasing, which may indicate that quality of performance (i.e., performance as intended) or execution of the corresponding action is progressively decreasing. Such trend may be indicative of declining condition of the actuator and/or component facilitating the corresponding action. The graph  640  may be generated by a processing device, such as the processing system  500 , based on recorded historical and current cycle times. The processing device may generate and output condition information indicative of the condition of the actuator and/or component of the piece of equipment based on the performance based condition indicators  642 . For example, the processing device may output condition information indicative of remaining life of the corresponding actuator and/or component. Furthermore, a threshold of acceptable condition, indicated by line  644 , may be set. Accordingly, if a predetermined number of consecutive performance based condition indicators  642  meet or exceed the threshold  642 , such as at time  648 , the processing device may at such time  648  output condition information suggesting or mandating that maintenance on the piece of equipment be performed. Furthermore, if a running average of the performance based condition indicators  642 , indicated by line  646 , meets or exceeds the threshold  644 , such as at time  648 , the processing device may at such time  648  output condition information suggesting or mandating that maintenance on the piece of equipment be performed. Although graph  640  shows a plurality of performance based condition indicators  642  indicative of cycle time, the processing device can record and analyze other performance based condition indicators for changes or trends over time, which are indicative of progressive decrease in quality of performance or execution of the corresponding action. 
       FIG. 10  is a flow-chart diagram of at least a portion of an example implementation of a process or method ( 700 ) according to one or more aspects of the present disclosure. The method ( 700 ) may be performed utilizing or otherwise in conjunction with at least a portion of one or more implementations of one or more instances of the apparatus shown in one or more of  FIGS. 1-9 , and/or otherwise within the scope of the present disclosure. For example, the method ( 700 ) may be performed and/or caused, at least partially, by a processing system (e.g., processing system  500  shown in  FIG. 7 ) executing program code instructions according to one or more aspects of the present disclosure. Thus, the following description of the method ( 700 ) also refers to apparatus shown in one or more of  FIGS. 1-9 . However, the method ( 700 ) may also be performed in conjunction with implementations of apparatus other than those depicted in  FIGS. 1-9  that are also within the scope of the present disclosure. 
     The method ( 700 ) may comprise operating ( 705 ) a piece of equipment  402  at an oil and gas wellsite by performing ( 710 ) a plurality actions by a component  408  of the piece of equipment  402  and generating ( 715 ) a plurality of sensor measurements, wherein each sensor measurement may be indicative of a corresponding action. The method ( 700 ) may further comprise receiving ( 720 ) the plurality of sensor measurements by a processing system  500 , calculating ( 725 ) a condition indicator for each component based on a corresponding sensor measurement, recording ( 730 ) each condition indicator over a period of time, and determining ( 735 ) condition of the piece of equipment  402  based on at least one of the condition indicators recorded over time. Each condition indicator may be indicative of performance of a corresponding action, and determining ( 735 ) the condition of the piece of equipment  402  may be based on change in at least one of the condition indicators recorded over time. The plurality of sensor measurements may be received ( 720 ) and the condition indicator may be calculated ( 725 ) in real-time while the actions are performed. The method ( 700 ) may further comprise outputting ( 740 ) information related to maintenance of the piece of equipment  402  when at least one of the condition indicators recorded over time meets or falls below a predetermined threshold. 
     The method ( 700 ) may further comprise calculating ( 745 ) the condition indicator for each component  408  further based on a control command configured to initiate a corresponding action. The method ( 700 ) may further comprise calculating ( 750 ) the condition indicator for each component  408  further based on a variance data indicative of a changed condition affecting at least one action thereby skewing a corresponding sensor measurement, wherein the variance data causes a shift in a corresponding sensor measurement to compensate for the changed condition. The method ( 700 ) may further comprise calculating ( 755 ) the condition indicator for each component  408  further based on a contextual data indicative of a changed condition affecting at least one action thereby invalidating a corresponding sensor measurement, wherein the contextual data causes a corresponding sensor measurement not to be used as a basis for calculating a corresponding condition indicator. 
     At least one of the sensor measurements may be indicative of position of an actuator  406  or component  408  of the piece of equipment  402  facilitating a corresponding action. At least one of the condition indicators may be indicative of travel time of an actuator  406  or component  408  of the piece of equipment  402  facilitating a corresponding action, average speed of an actuator  406  or component  408  of the piece of equipment  402  facilitating a corresponding action, or maximum speed of an actuator  406  or component  408  of the piece of equipment  402  facilitating a corresponding action. 
     In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces a computer program product comprising a non-transitory, computer-readable medium comprising instructions that, when executed by a processor of a processing system, cause the processing system to: receive a plurality of sensor measurements each generated by a corresponding sensor of a piece of equipment at an oil and gas wellsite, wherein the piece of equipment comprises a plurality of actuators each operable to facilitate a corresponding action performed by a component of the piece of equipment, and wherein each sensor measurement is indicative of a corresponding action; generate a condition indicator for each sensor based on a corresponding sensor measurement; record each condition indicator over a period of time; and determine condition of the piece of equipment based on at least one of the condition indicators recorded over time. 
     Each condition indicator may be indicative of performance of a corresponding action facilitated by a corresponding actuator. 
     The instructions may cause the processing system to determine the condition of the piece of equipment based on change in at least one of the condition indicators recorded over time. The instructions may cause the processing system to output information related to maintenance of the piece of equipment when at least one of the condition indicators recorded over time meets or falls below a predetermined performance threshold. 
     The instructions may cause the processing system to generate the condition indicator for each sensor further based on a control command configured to initiate a corresponding action. 
     The instructions may cause the processing system to generate the condition indicator for at least one of the sensors further based on a variance data indicative of a changed condition affecting at least one action thereby skewing a corresponding sensor measurement, and the variance data may cause a shift in a corresponding sensor measurement to compensate for the changed condition. 
     The instructions may cause the processing system to generate the condition indicator for at least one of the sensors further based on a contextual data indicative of a changed condition affecting at least one action thereby invalidating a corresponding sensor measurement, and the contextual data may cause a corresponding sensor measurement not to be used as a basis for calculating a corresponding condition indicator. 
     At least one of the sensor measurements may be indicative of position of a corresponding actuator or component of the piece of equipment during a corresponding action. 
     At least one of the condition indicators may be indicative of: travel time of a corresponding actuator or component of the piece of equipment during a corresponding action; average speed of a corresponding actuator or component of the piece of equipment during a corresponding action; or maximum speed of a corresponding actuator or component of the piece of equipment during a corresponding action. 
     The instructions may cause the processing system to receive the plurality of sensor measurements and generate the condition indicators for each sensor in real-time while the actuators facilitate corresponding actions. 
     The present disclosure also introduces a method comprising operating a piece of equipment at an oil and gas wellsite by: performing a plurality actions by a component of the piece of equipment; and generating a plurality of sensor measurements, wherein each sensor measurement is indicative of a corresponding action. The method may also comprise receiving the plurality of sensor measurements by a processing system; calculating a condition indicator for each component based on a corresponding sensor measurement; recording each condition indicator over a period of time; and determining condition of the piece of equipment based on at least one of the condition indicators recorded over time. 
     Each condition indicator may be indicative of performance of a corresponding action. 
     Determining the condition of the piece of equipment may be based on change in at least one of the condition indicators recorded over time. The method may comprise outputting information related to maintenance of the piece of equipment when at least one of the condition indicators recorded over time meets or falls below a predetermined performance threshold. 
     The method may comprise calculating the condition indicator for each component further based on a control command configured to initiate a corresponding action. 
     The method may comprise calculating the condition indicator for each component further based on a variance data indicative of a changed condition affecting at least one action thereby skewing a corresponding sensor measurement, and the variance data may cause a shift in a corresponding sensor measurement to compensate for the changed condition. 
     The method may comprise calculating the condition indicator for each component further based on a contextual data indicative of a changed condition affecting at least one action thereby invalidating a corresponding sensor measurement, and the contextual data may cause a corresponding sensor measurement not to be used as a basis for calculating a corresponding condition indicator. 
     At least one of the sensor measurements may be indicative of position of an actuator or component of the piece of equipment facilitating a corresponding action. 
     At least one of the condition indicators may be indicative of: travel time of an actuator or component of the piece of equipment facilitating a corresponding action; average speed of an actuator or component of the piece of equipment facilitating a corresponding action; or maximum speed of an actuator or component of the piece of equipment facilitating a corresponding action. 
     The plurality of sensor measurements may be received and the condition indicator may be generated in real-time while the actions are performed. 
     The present disclosure also introduces a system comprising: (A) a piece of equipment at an oil and gas wellsite comprising: (1) a plurality of actuators each operable to facilitate a corresponding action by a component of the piece of equipment; and (2) a plurality of sensors each operable to generate a signal indicative of an operational parameter associated with a corresponding action; (B) a processing system comprising a processor and a memory storing a computer program code that, when executed, causes the processing system to: (1) receive the plurality of signals; (2) generate a condition indicator for each action based on a corresponding signal; (3) record each condition indicator over a period of time; and (4) determine condition of the piece of equipment based on at least one of the condition indicators recorded over time. 
     Each condition indicator may be indicative of quality of performance of a corresponding action. 
     The condition of the piece of equipment may be determined based on change in at least one of the condition indicators recorded over time. The computer program code may cause the processing system to output information related to maintenance of the piece of equipment when at least one of the condition indicators recorded over time meets or falls below a predetermined performance threshold. 
     The computer program code may cause the processing system to generate the condition indicator for each action further based on a control command configured to initiate a corresponding action. 
     The computer program code may cause the processing system to generate the condition indicator for each action further based on a variance data indicative of a changed condition affecting at least one action thereby skewing a corresponding signal, and the variance data may cause a shift in a corresponding signal to compensate for the changed condition. 
     The computer program code may cause the processing system to generate the condition indicator for each action further based on a contextual data indicative of a changed condition affecting at least one action thereby invalidating a corresponding signal, and the contextual data may cause a corresponding signal not to be used as a basis for calculating a corresponding condition indicator. 
     At least one of the operational parameters may comprise position of the actuator or component of the piece of equipment while a corresponding action is performed. 
     At least one of the condition indicators may be indicative of: travel time of the actuator or component of the piece of equipment while a corresponding action is performed; average speed the an actuator or component of the piece of equipment while a corresponding action is performed; or maximum speed of the actuator or component of the piece of equipment while a corresponding action is performed. 
     The plurality of sensor measurements may be received and each condition indicator may be generated in real-time while the actions are performed. 
     The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure. 
     The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.