Patent Publication Number: US-9896926-B2

Title: Intelligent cement wiper plugs and casing collars

Description:
BACKGROUND 
     The present disclosure is related to wellbore operations and, more particularly, to intelligent casing collars and cement wiper plugs used in wellbore cementing operations. 
     During completion of oil and gas wells, cement is often used to solidify a well casing within the newly drilled wellbore. To accomplish this, cement slurry is first pumped through the inner bore of the well casing and either out its distal end or through one or more ports defined in the well casing at predetermined locations. Cement slurry exits the well casing into the annulus formed between the well casing and the wellbore, and is then pumped back up toward the surface within the annulus. Once the cement hardens, it forms a seal between the well casing and the wellbore to protect oil producing zones and non-oil producing zones from contamination. In addition, the cement bonds the casing to the surrounding rock formation, thereby providing support and strength to the casing and also preventing blowouts and protecting the casing from corrosion. 
     Prior to cementing, the wellbore and the well casing are typically filled with drilling fluid or mud. A cementing plug is then pumped ahead of the cement slurry in order to prevent mixing of the drilling mud already present within the wellbore with the cement slurry. When the cementing plug reaches a float collar or cement plug arranged within the casing at a predetermined location, the hydraulic pressure of the cement slurry ruptures the cement plug and enables the cement slurry to pass through the plug and then through either the distal end of the casing or the side ports and into the annulus. Subsequently, another cementing plug is pumped down the casing to prevent mixing of the cement slurry with additional drilling mud that will be pumped into the casing following the cement slurry. When the top cementing plug lands on the casing collar or the cement plug, the pumping of the cement slurry ceases. 
     Prior to, during, and following the cementing operation, it may prove advantageous to monitor and transmit various wellbore parameters relating to the cementing operation to ensure that operations are proceeding and completed as designed. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure. 
         FIG. 1  is an exemplary well system that may employ the principles of the present disclosure, according to one or more embodiments. 
         FIGS. 2A and 2B  illustrate the well system of  FIG. 1  in exemplary operation, according to one or more embodiments. 
         FIG. 3  illustrates another exemplary well system that may employ the principles of the present disclosure, according to one or more embodiments. 
         FIG. 4  illustrates an exemplary intelligence system that may exemplary intelligence system used to measure orientation of a casing string, according to one or more embodiments. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure is related to wellbore operations and, more particularly, to intelligent casing collars and cement wiper plugs used in wellbore cementing operations. 
     The exemplary casing collars and cement wiper plugs described in the present disclosure are embedded with electronic and/or mechanical devices that provide each component with intelligence and communication capabilities (both transmitting and receiving). In operation, the exemplary casing collars may be configured to monitor fluids, such as drilling fluids, spacer fluids and cement slurries, flowing within an annulus defined between the casing string and the walls of the wellbore. For instance, the casing collars may have multiple sensors configured to detect various parameters related to the fluids and transmit these measurements to the exemplary cement wiper plug. The cement wiper plug may include a pulser, such as a mud pulser, that is able to communicate with the surface through pressure pulses conveyed through the fluid column in the casing string, and thereby transmit the measurement data obtained from the sensors to a surface location. The disclosed embodiments may prove advantageous in providing a well operator with real-time data regarding cementing operations downhole. 
     Referring to  FIG. 1 , illustrated is an exemplary well system  100  that may employ the principles of the present disclosure, according to one or more embodiments. The well system  100  may include an oil and gas rig  102  arranged at the Earth&#39;s surface  104  and a wellbore  106  extending therefrom and penetrating a subterranean earth formation  108 . As depicted in  FIG. 1 , the rig  102  may be representative of any type of wellbore drilling or servicing rig including, but not limited to, land-based oil and gas rigs, offshore platforms, offshore service rigs, and any wellhead installation known to those skilled in the art. Accordingly, the surface  104  may be representative of the sea level in offshore applications. 
     As illustrated, the wellbore  106  may extend substantially vertically away from the surface  104 . In other embodiments, the wellbore  106  may otherwise deviate at any angle from the surface  104  over a deviated or horizontal portion. In other applications, portions or substantially all of the wellbore  106  may be vertical, deviated, horizontal, and/or curved. Moreover, use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole, and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the bottom of the well. 
     As illustrated, a casing string  110  may be extended within the wellbore  106  from the surface  104 , thereby defining an annulus  112  between the walls of the wellbore  106  and the casing string  110 . As used herein, the term “casing string” refers to one or more types of connected lengths of tubulars or pipe. In some embodiments, “casing string” refers to the common meaning of casing as used by those skilled in the art. In other embodiments, however, “casing string” may refer to surface casing, intermediate casing, production tubing, wellbore liner, combinations thereof, or the like. A float shoe  113  may be arranged at the bottom or distal end of the casing string  110 . The float shoe  113  may include or otherwise define at least one hole  114  therein configured to provide fluid communication between the annulus  112  and the interior of the casing string  110 . In some embodiments, an integral check valve (not shown) may be arranged within the hole  114  and used to prevent reverse flow or “U-tubing” of various fluids into the casing string  110  from the annulus  112  during operation. 
     The well system  100  may further include a casing collar  116  and a cement wiper plug  118 . The casing collar  116  may be arranged about or otherwise form an integral part of the casing string  110 . The casing collar  116  may generally be used to connect two axially adjacent sections or joints of the casing string  110 , shown as an upper casing section  114   a  and a lower casing section  114   b . Moreover, however, the casing collar  116  may be embedded with various electronic and/or mechanical devices configured to provide the casing collar  116  with intelligence and communication capabilities. 
     For instance, the casing collar  116  may include one or more sensors  120  (one shown) arranged within a cavity  122  defined in the casing collar  116 . While only one sensor  120  is shown in  FIG. 1 , it will be appreciated that more than one sensor  120  may be employed in the casing collar  116 , without departing from the scope of the disclosure. In some embodiments, for example, several sensors  120  may be arranged within the cavity  122 . In other embodiments, multiple sensors  120  may be arranged about the circumference of the casing collar  116 , as will be described in greater detail below. 
     The sensors  120  may be configured to monitor or otherwise measure various wellbore parameters, such as properties of fluids that may be present within the annulus  112 . Accordingly, the sensors  120  may include a variety of different sensors including, but not limited to, temperature sensors (measurements taken in both inner and outer diameters), pressure sensors (measurements taken in both inner and outer diameters), one or more strain gauges or sensors (i.e., to measure weight, tension, compression, bending moment, etc.), pH sensors, density sensors, viscosity sensors, chemical composition sensors (e.g., sensors capable of determining the chemical makeup of fluids and otherwise capable of comparing chemical compositions of different fluids), radioactive sensors (e.g., gamma, neutron, and proton), sonic emitters and receivers, resistivity sensors, sonic or acoustic sensors, self/spontaneous potential sensors, mechanical sensors (e.g., caliper logs and the like), nuclear magnetic resonance logging sensors, and the like. 
     A communications module  124  may also be arranged within the cavity  122  of the casing collar  116 . The communications module  124  may include one or more of a receiver, a transmitter, a transceiver, a power source, a computer, and a memory storage device. In some embodiments, the memory storage device may be sealed or substantially sealed (e.g., one or more fluid and/or pressure barriers) from the fluids from the surrounding environment in order to protect fragile electrical components associated therewith. The communications module  124  may be configured to receive the measurements obtained from the sensors  120  in real-time. In some embodiments, the measurement signals from the sensors  120  may be stored in the associated memory storage device. In other embodiments, however, the measurement signals from the sensors  120  may be conveyed or otherwise transmitted (either wired or wirelessly) to the cement wiper plug  118 , as will be discussed in more detail below. 
     The cement wiper plug  118  may be arranged within the casing string  110  at or near the casing collar  116 . The casing collar  116  may be communicably coupled to the cement wiper plug  118  such that it is able to transmit measurement data thereto. In some embodiments, the cement wiper plug  118  may be run in hole from the surface  104  at the same time the casing string  110  is conveyed downhole. In other words, in some embodiments, the cement wiper plug  118  may be mechanically and electrically coupled to the interior of the casing string  110  and otherwise form an integral part thereof. In other embodiments, however, the cement wiper plug  118  may be conveyed downhole once the casing string  110  is landed or otherwise situated within the wellbore  106 . In such embodiments, the blades or wipers  126  of the cement wiper plug  118  may be configured to locate a corresponding profile or groove defined on the inner radial surface of the casing string  110  and thereby secure itself therein. Once properly secured within the casing string  110 , the cement wiper plug  118  may become mechanically and electrically coupled thereto. 
     The cement wiper plug  118  may include a power source  128 , computer hardware  130 , and a pulser  132 . The power source  128  may be any device or mechanism capable of providing power to the computer hardware  130  and the pulser  132 . In some embodiments, the power source  128  may also provide power to the casing collar  116  and its associated components described above. The power source  128  may be one or more batteries or fuel cells, such as alkaline or lithium batteries. In other embodiments, the power source  128  may be a terminal portion of an electrical line (i.e., e-line) extending from the surface  104 . In yet other embodiments, the power source  128  may encompass power or energy derived from a downhole power generation unit or assembly, as known to those skilled in the art. 
     The computer hardware  130  may be configured to implement the various methods described herein and can include a processor configured to execute one or more sequences of instructions, programming stances, or code stored on a non-transitory, computer-readable medium. The processor can be, for example, a general purpose microprocessor, a microcontroller, a digital signal processor, an application specific integrated circuit, a field programmable gate array, a programmable logic device, a controller, a state machine, a gated logic, discrete hardware components, an artificial neural network, or any like suitable entity that can perform calculations or other manipulations of data. In some embodiments, the computer hardware  130  can further include elements such as a memory (e.g., random access memory (RAM), flash memory, read only memory (ROM), programmable read only memory (PROM), electrically erasable programmable read only memory (EEPROM)), registers, hard disks, removable disks, CD-ROMS, DVDs, or any other like suitable storage device or medium. 
     The computer hardware  130  may be communicably coupled to the pulser  132  such that the computer hardware  130  is able to control or otherwise actuate the pulser  132  upon command. As illustrated, the pulser  132  may be a mud pulser and may include an actuator  134  and a rocker arm  136  operatively coupled to the actuator  134  such that movement of the actuator  134  correspondingly moves the rocker arm  136 . The actuator  134  may be any type of actuating device including, but not limited to, a mechanical actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, combinations thereof, and the like. 
     The rocker arm  136  may be pivotably coupled to the actuator  134  such that when the actuator  134  is actuated, the rocker arm  136  pivots into a flow path  138  centrally defined within the cement wiper plug  118 . As it pivots into the flow path  138 , the rocker arm  136  at least partially occludes the flow path  138  and is thereby able to transmit pressure pulses to the surface  104  via the fluid column present within the interior of the casing string  110 . At the surface  104 , the pressure pulses are received by one or more sensors of a computer system  140  arranged on the rig  102  and converted into an amplitude or frequency modulated pattern of fluid pulses. The pattern of fluid pulses may then be translated by the computer system  140  into specific information or data transmitted by the computer hardware  130  of the pulser  132 . 
     It will be appreciated by those skilled in the art that while the pulser  132  is depicted in  FIG. 1  as including a specific design and configuration including the actuator  134  and the rocker arm  136 , several variations of the pulser  132  may be employed to equally accomplish the same end, without departing from the scope of the disclosure. Indeed, various other types and designs of pulsers, including other types besides mud pulsers, are readily available and also capable of transmitting pressure pulses to the surface  104  via the fluid column within the casing string  110 . Accordingly, the pulser  132  is shown and described herein as merely illustrative and therefore should not be considered limiting to the present disclosure. 
     Moreover, in other embodiments, the communications module  124  may be configured to transmit information to/from the computer system  140  at the surface  104 . For instance, in at least one embodiment, the communications module  124  may be capable of real-time acoustic telemetry with the computer system  140  which may be associated with an electronic acoustic receiver attached to the top drive on the rig  102 . The acoustic signal may be transmitted via several repeaters or “nodes” positioned at pre-determined locations within the casing string  110  to provide optimum signal strength and transmission speed, depending upon the angle of the hole. The nodes are a collar-based design utilizing an outer housing with an internal mandrel providing space between for batteries, sensors, electronic boards and a piezoelectric stack used to transmit the acoustic signals. In some embodiments, the nodes can be approximately the same length as drill pipe and utilize the same threads as drill string tool joints. 
     The computer system  140  may be configured to receive the acoustic signals and transmit any received signals to a decoding center. Following decoding, the signal may be transmitted to a number of locations dependent upon the operator&#39;s preference. The decoded data may also be displayed in graphic form, thereby allowing the operator to see even small changes in the downhole environment. Alternatively, this data can be held in memory until tripped out of the hole, thereby also providing along-string measurements of downhole events. Because of its potentially high data rate, those skilled in the art will appreciate the advantages of using acoustic telemetry. For instance, the operating frequency band of acoustic telemetry is much higher and broader than mud pulse, ranging from 400 Hz to 2 KHz. Moreover, acoustic telemetry operates in virtually any drilling or completions environment since it is independent of fluid flow and is not restricted by high-resistivity formations. This makes using acoustic telemetry well suited for providing pressure data visibility in under-balance drilling or managed-pressure drilling applications. 
     The casing collar  116  may be arranged in the wellbore  106  such that the sensors  120  are disposed at or above a critical zone  142  defined within the subterranean formation  108 . The critical zone  142  may be a zone of interest that may include certain fluids or chemicals that a well operator may want to restrict through a cementing operation within the annulus  112 . For instance, the critical zone  142  may include corrosive fluids or chemicals that may corrode the casing string  110  if not properly sealed. In other embodiments, the critical zone  142  may be a hydrocarbon-producing zone that the well operator would like to also seal off such that hydrocarbons do not leak into the annulus  112  but instead may be intelligently produced to the surface. 
     Referring now to  FIGS. 2A and 2B , illustrated is the well system  100  of  FIG. 1  in exemplary operation, according to one or more embodiments. In  FIG. 2A , a drilling fluid  202  or “mud” may be disposed within the casing string  110 . More particularly, the drilling fluid  202  may be circulated through the wellbore  106  from the surface  104  ( FIG. 1 ) by flowing down through the interior of the casing string  110  and also through the flow path  138  defined within the cement wiper plug  118 . At the bottom of the casing string  110 , the drilling fluid  202  exits into the annulus  112  via the float shoe  113  and is then pumped back up toward the surface  104  within the annulus  112 . As mentioned above, the check valve (not shown) may be arranged within the hole  114  to prevent reverse flow of the drilling fluid  202  back into the casing string  110  from the annulus  112 . 
     While the drilling fluid  202  is circulated through the wellbore  106 , the sensors  120  may be monitoring the drilling fluid  202 . In some embodiments, measurements are taken continuously by the sensors  120 . In other embodiments, measurement are taken at predetermined times or otherwise intermittently by the sensors  120 . The measurements taken by the sensors  120  may include, but are not limited to, pressure, temperature, density of the drilling fluid  202 , chemical composition of the drilling fluid  202 , gas-cut of the drilling fluid  202  (e.g., how much gas is entrained in the drilling fluid  202 ), and the presence of oil and/or gas within the drilling fluid  202 . 
     Monitoring the presence of oil, water (e.g., formation water, hard water, saltwater, fresh water), emulsions of oil and water, other formation fluids (i.e., paraffins, waxes, light oils, etc.), and/or gas within the drilling fluid  202  may help ensure that the wellbore  106  is sufficiently stable for a cementing operation. More particularly, such measurements may provide a well operator with the hydrostatic head pressure within the annulus  112  to ensure that the pore pressure of the formation  108  is at least slightly lower than the hydrostatic head such that the influx of oil, water, and/or gas or toxic chemicals into the annulus  112  is generally prevented. Water from formations can lighten the weight of the drilling fluid  202  also. If the hydrostatic head is reduced, more oil, water and/or gas can flow into the wellbore  106  and thereby lighten the weight of the drilling fluid  202  to a greater extent. Well control issues can occur if the weight of the drilling fluid  202  is lightened too much. 
     In at least some embodiments, the measurements obtained by the sensors  120  may be conveyed to the cement wiper plug  118  in real-time, and the computer hardware  130  may be configured to receive and process these measurements. In some embodiments, the computer hardware  130  may be configured to store the pre-processed or processed measurements. In other embodiments, the computer hardware  130  may be configured to translate the processed measurements into a command signal transmitted to the pulser  132 . 
     The command signal may be received by the pulser  132  and serve to actuate the pulser  132  such that the rocker arm  136  is engaged to partially occlude the flow path  138  and thereby transmit pressure pulses to the surface  104  ( FIG. 1 ) via the fluid column present within the casing string  110 . Actuation of the pulser  132  is shown in  FIG. 2B . At the surface  104 , the pressure pulses may be received by the computer system  140  ( FIG. 1 ), such as with one or more surface sensors, and retranslated back into the measurement data such that the well operator may be apprised of the parameters of the drilling fluid  202  being measured downhole. 
     Referring to  FIG. 2B , a spacer fluid  204  may be pumped into the casing string  110  and otherwise circulated through the wellbore  106  following the drilling fluid  202 . As illustrated, the spacer fluid  204  has been pumped through the casing string  110 , exited the bottom of the casing string  110  at the float shoe  113 , and is returning to the surface  104  via the annulus  112 . The spacer fluid  204  may follow the drilling fluid  202  and otherwise hydraulically push the drilling fluid  202  back to the surface  104  as it advances through the wellbore  106 . 
     The spacer fluid  204  may be any fluid that is different from the drilling fluid  202  including, but not limited to, freshwater, brines, and slurries that include materials, chemicals and additives blended together at engineered concentrations. In some embodiments, the spacer fluid  204  may be a “plug” or a “pill” of the spacer fluid  204 , meaning that the spacer fluid  204  encompasses a predetermined volume, such as around  20  barrels or more. The plug of spacer fluid  204  may follow the drilling fluid  202  and otherwise serve to separate the drilling fluid  202  from another fluid, such as a concrete slurry to be circulated through the wellbore  106  following the spacer fluid  204 . 
     According to some embodiments, the sensors  120  may be configured to detect or otherwise sense when the spacer fluid  204  passes the sensors  120 , thereby enabling a well operator to determine the volume of cement slurry required to be pumped to cover or otherwise seal the critical zone  142 . More particularly, the sensors  120  may be configured to measure a fluid property corresponding to the drilling fluid  202  in the annulus  112 . The fluid property being monitored may include, but is not limited to, density, viscosity, pH level, chemical composition (e.g., acetylene gas concentration), yield stress, shear sensitivity, flow rate, radioactivity (e.g., in the case of radioactive tracers), salinity, alkalinity, oil-cut, presence of oil, fluid loss, combinations thereof, and the like. Once the fluid property being measured changes or otherwise becomes a fluid property corresponding to the spacer fluid  204 , the communications module  124  may communicate the same to the cement wiper plug  118 , which transmits this information to the surface  104  via the pulser  132 . Given a known flow rate of the spacer fluid  204  being pumped from the surface  104 , in conjunction with the timing required for the measured fluid property to switch from the drilling fluid  202  to the spacer fluid  204 , a well operator may be able to determine or otherwise calculate how much cement is needed to surpass the critical zone  142  within the annulus  112 . 
     In some embodiments, pumping of the spacer fluid  204  may be stopped once the spacer fluid  204  reaches or otherwise surpasses the sensors  120  within the annulus  112 . While pumping is stopped, the sensors  120  may be configured to monitor the pressure within the annulus  112  to determine if fluids are falling into “loss zones” via vugs, fissures, fractures or other permeabilites in the surrounding formation  108  or critical zone  142 . If the pressure within the annulus  112  drops, this may be an indication that fluids are being lost into loss zones of the formation  108 . As will be appreciated, this may prove advantageous in determining if the hydrostatic head within the annulus  112  is greater/heavier than what the formation  108  can withstand, and therefore may be an indication as to whether cement would also be lost into the formation  108  during cementing. Any measured pressure decrease may be transmitted to the surface  104  via the cement wiper plug  118  and the pulser  132 , and the well operator may be able to determine how much hydrostatic pressure the formation  108  can hold and therefore how much extra cement slurry will need to be pumped to appropriately seal the wellbore  106 . 
     Moreover, in response to the data transmitted to the surface  104 , one or more properties of the cement slurry and/or the spacer fluid  204  can be modified to enhance/improve the quality of a subsequent cementing job. For example, the weight of the cement slurry may be increased if the formation pressure is greater than anticipated. As will be appreciated, increasing the weight of the cement slurry may help prevent formation fluids from encroaching into the wellbore  106  and migrating upwards by creating micro annuli. 
     In some embodiments, two casing collars  116  (not shown) may be arranged on either side of a critical zone  142  (i.e., axially above and below the critical zone  142 ). Once the spacer fluid  204  is sensed or otherwise detected by the lower casing collar (e.g., time=T 1 ), a pulse may be sent to the surface  104  providing positive indication that the spacer fluid  204  has been sensed. After a time, the spacer fluid  204  may be sensed or otherwise detected by the upper casing collar (e.g., time=T 2 =T 1 +ΔT 1 ), and another pulse may be sent to the surface  104  providing positive indication that the spacer fluid  204  has been sensed at the upper casing collar. By knowing the volume of the wellbore  106  between the lower and upper casing collars, and by pumping at a constant rate, the time for the pill of the spacer fluid  204  to reach each casing collar can be calculated. 
     If the actual time is longer than calculated, then it can be surmised that some of the fluid is being lost, for example, by seeping into the critical zone  142 , which may be a low pore-fracture pressure zone. If the hydrostatic head pressure is greater than the pressure in the critical zone  142 , the spacer fluid  204  will “fall” downhole and enter the critical zone  142 . During this time, both casing collars may be recording the activity. For instance, the upper casing collar may detect an increase in the property being measured with the sensors  120  (e.g., radioactivity), and then a decrease as the pill passes thereby. If the pill moves into the critical zone  142 , then the lower casing collar will not sense a change in the property being measured. The time when the upper casing collar first senses the spacer fluid  204  moving down past it and when the property being measured drops to a magnitude indicating that the majority of the pill has fallen past the upper casing collar may be useful in providing a means for estimating how fast the critical zone  142  is taking the pill. 
     The hydrostatic pressure at the upper casing collar may also be used to determine the hydrostatic head and pressure of the critical zone  142 . If the critical zone  142  is not taking fluid, for example, the hydrostatic head will be calculated. If the critical zone  142  is taking fluid, however, the pore-fracture pressure of the critical zone  142  may be measured using the sensors  120 . It will be appreciated that multiple pills or slugs (or repeats thereof) of the spacer fluid  204  may be pumped in order to check for losses into the critical zone  142 . 
     In some embodiments, the sensors  120  may be configured to monitor the annulus  112  for a cement slurry (not shown) pumped from the surface  104  following the spacer fluid  204  and configured to seal the wellbore  106  or otherwise cover the critical zone  142 . For example, the sensors  120  may be configured to monitor a fluid property of the cement slurry, such as density, viscosity, pH level, chemical composition, combinations thereof, and the like. As soon as the cement slurry is detected by the sensors  120 , the communications module  124  may communicate the same to the cement wiper plug  118  and the information may be transmitted to the surface  104  via the pulser  132 . Knowing when the cement slurry has passed the sensors  120  may prove advantageous in providing a positive indication to the well operator that the critical zone  142  has indeed been covered or otherwise surpassed with the cement slurry. 
     In some embodiments, the sensors  120  may be configured to continuously monitor the fluid properties of the cement slurry within the annulus  112  as the cement is circulated within the wellbore  106 . Fluid properties such as density, viscosity, and pH may be especially important parameters to monitor as they may correspond to the overall quality of the cement placed in the annulus  112 . Knowing the quality of the cement may prove advantageous in providing assurances of its robustness and ability to properly seal the wellbore  106 . In embodiments where the cement slurry is foam cement being circulated through the wellbore  106  and used to seal the annulus  112 , the sensors  120  may be used to measure the quantity and/or quality of the gas suspended in the foam cement. For instance, the sensors  120  may be configured to monitor or measure the density of the foam cement and report the same to the surface  104 . 
     In some embodiments, the amount of measurement data recovered may be too much to transmit with the cement wiper plug  118  while circulating and cementing the casing string  110 . In such embodiments, another option for data retrieval would be to retrieve the cement wiper plug  118  (or just the data) from the wellbore  106  following the cementing job. This may be accomplished using, for example, wireline or slickline as extended from the surface  104  ( FIG. 1 ). Once the cement wiper plug  118  is retrieved to the surface  104 , the measurement data stored in the memory associated with the computer hardware  130  may be downloaded for processing and post-job analysis. In yet other embodiments, the measurement data may be conveyed to the surface  104  using a combination of data transmission via the cement wiper plug  118  while downhole and also retrieving part (or all) of the cement wiper plug  118  to the surface  104 . 
     In yet other embodiments, the measurement data obtained by the sensors  120  may be retained in the memory associated with the communications module  124 . In order to obtain such stored measurement data, a drill string including an associated bottom hole assembly (BHA) (not shown) may be introduced into the wellbore  106  as it is being tripped in to continue drilling operations below the bottom of the casing string  110 . The measurement data stored in the communications module  124  may be transferred wirelessly to the BHA as it passes the casing collar  116 . The transmitters and receivers associated with each component may send and receive radio frequency (RF) signals, infrared (IR) frequency signals, or other electromagnetic signals. Any of a variety of modulation techniques may be used to modulate data on a respective electromagnetic carrier wave or acoustic carrier wave or other energy source/receiver. 
     The retrieved data may then be transmitted to the surface  104  via mud pulse telemetry associated with the BHA or via wired drill pipe. In other embodiments, the data retrieved by the BHA may instead be stored in a memory associated with the BHA for recovery when the BHA is tripped out of the wellbore  106 . In yet other embodiments, the retrieved data may be stored in the memory associated with the BHA until drilling is commenced at which point the data may be transmitted to the surface  104  via mud pulse or other telemetry methods, such as acoustic telemetry. As will be appreciated, running the BHA past the casing collar  116  may also allow charging of any power storage devices (not shown) associated therewith, such as via induction charging techniques. Thus allowing additional sensor data to be acquired, stored, computed and transmitted at a later date (e.g., up to the end of the life of the well or longer). 
     Referring now to  FIG. 3 , with continued reference to the preceding figures, illustrated is another exemplary well system  300  that may employ the principles of the present disclosure, according to one or more embodiments. The well system  300  may be similar in some respects to the well system  100  of  FIG. 1  and therefore may be best understood with reference thereto, where like numerals represent like elements not described again in detail. The well system  300  may include an oil and gas rig  302  arranged at the Earth&#39;s surface  104  and the wellbore  106  extends therefrom and penetrates the subterranean earth formation  108 . The casing string  110  is depicted as extending from the rig  302  and into the wellbore  106 , thereby defining the annulus  112  therebetween. As depicted, a fluid  304  may be introduced into the wellbore  106  via the casing string  110  and return to the surface  104  via the annulus  112 , as generally described above. The fluid  304  may be representative of the drilling mud  202  or the spacer fluid  204  of  FIGS. 2A-2B , but may also be representative of a cement slurry used to cement the casing string  110  within the wellbore  106 . 
     While depicting a land-based service rig in  FIG. 3 , the rig  302  may equally be replaced with any other type of wellbore rig including, but not limited to, offshore platforms, offshore service rigs, and any wellhead installation (used for construction, drilling, completing, producing, servicing, stimulating, etc.) known to those skilled in the art. Accordingly, the surface  104  may equally be representative of the sea level in offshore applications. 
     The well system  300  may include a plurality of casing collars  116  (shown as casing collars  116   a ,  116   b ,  116   c , and  116   d ) arranged in or otherwise forming an integral part of the casing string  110  at predetermined locations along the length of the casing string  110 . Similar to the casing collar  116  of  FIG. 1 , one or more of the casing collars  116   a - d  may be embedded with various electronic and/or mechanical devices configured to provide the corresponding casing collar  116   a - d  with intelligence and communication capabilities. In some embodiments, one or more of the casing collars  116   a - d  may further include energy storage capabilities and/or an independent power supply. In at least one embodiment, one or more of the casing collars  116   a - d  may also include a means of recharging the energy/power supply (i.e., rechargeable batteries), as generally described above. 
     In some embodiments, for example, one or more of the casing collars  116   a - d  may include sensors  120  (shown as sensors  120   a ,  120   b ,  120   c , and  120   d ). Similar to the sensors  120  of  FIG. 1 , the sensors  120   a - d  may be configured to monitor or otherwise measure properties of fluids (e.g., the fluid  304 ) that may be present within the annulus  112 . Accordingly, the sensors  120   a - d  may encompass a variety of different sensors including, but not limited to, temperature sensors, pressure sensors, pH sensors, density sensors, viscosity sensors, chemical composition sensors, and the like. 
     Moreover, one or more of the casing collars  116   a - d  may further include a communications module  124  (shown as communications modules  124   a ,  124   b ,  124   c , and  124   d ) associated therewith. Similar to the communications module  124  of  FIG. 1 , the communications modules  124   a - d  may each include one or more of a receiver, a transmitter, a transceiver, a power source, timers, counters, and a memory storage device. The communications modules  124   a - d  may be configured to receive the measurements obtained from the sensors  120   a - d  in real-time. In some embodiments, the measurement signals from the sensors  120   a - d  may be stored in the associated memory storage device. In other embodiments, however, the measurement signals from the sensors  120   a - d  may be conveyed or otherwise transmitted (either wired or wirelessly) to the surface  104  for processing and consideration by a well operator. 
     While only four casing collars  116   a - d  are shown in  FIG. 3 , it will be appreciated that more or less than four casing collars  116   a - d  and associated sensors  120   a - d  may be employed, without departing from the scope of the disclosure. Moreover, while not depicted in  FIG. 3 , one or more of the casing collars  116   a - d  may include an associated one or more cement wiper plugs  118  arranged within the casing string  110  at or near the particular casing collar  116   a - d . Operation of such a cement wiper plug  118  in conjunction with the associated casing collar  116   a - d  may proceed as generally described above with reference to  FIGS. 2A-2B  and therefore will not be described again. As the casing string  110  is being lowered into the wellbore  106 , each of the casing collars  116   a - d  may be active and otherwise monitoring various wellbore parameters such as, but not limited to, hole diameter, temperature, pressure, pH, radioactivity, etc. 
     In some embodiments, the sensors  120   a - d  in one or more of the casing collars  116   a - d  may be spaced about the circumference of the casing string  110 . For example, and not by limitation, the third casing collar  116   c  may include multiple sensors  120   c  (only one shown) spaced either equidistantly or randomly around the circumference of the casing string  110  at that location within the wellbore  106 . As a result, the sensors  120   c  may be able to monitor fluid properties of the fluid  304  within the annulus  112  at a corresponding plurality of angles about the casing string  110 . The monitored or measured fluid properties may be transmitted (either wired or wirelessly) to the surface  104  using the communications module  124   c . In other embodiments, however, an associated cement wiper plug (not shown) may be arranged within the casing string  110  adjacent the third casing collar  116   c  and may otherwise transmit the monitored or measured fluid properties obtained by the sensors  120   c  to the surface  104  as generally described herein. It will be appreciated that more than one cement wiper plug may be arranged within the casing string  110  adjacent the third casing collar  116   c  as well. 
     Such an embodiment may prove advantageous in monitoring the flow profile of the fluid  304  for micro-annuli that may potentially form in horizontal and/or deviated portions of the wellbore  106 . For example, if not properly centralized, the casing string  110  within horizontal and/or deviated portions of the wellbore  106  may tend to lie on the low side of the wellbore  106 . Upon encountering an improperly centralized casing string  110 , the fluid  304  may take the path of least resistance and flow to the high side of the wellbore  106  where a larger gap would exist. If one of the sensors  120   c  detects a flow profile (e.g., flow rate and/or pressure change (drop)) different from the other sensors  120   c , such as by a predetermined amount, that may be an indication of a poorly placed or centralized casing string  110 . During cementing operations, when the fluid  304  consists of a cement slurry, a poorly placed casing string  110  may result in micro-annulus formation between the casing string  110  and the walls of the wellbore  106 . In such locations, the cement may be too thin on the low side of the wellbore  106  and therefore may be susceptible to failure. By detecting a poorly placed casing string  110  during circulating and conditioning of the wellbore  106  (e.g., the circulation that occurs before pumping spacers and cement), methods such as manipulating the casing string  110  and adding additives to the drilling fluid, spacer fluid, and/or cement slurry to improve the placement of the casing string  110  can be used. 
     Instead of transmitting the measurement data from the sensors  120   a - c  to the surface  104  in real-time via the corresponding communication modules  124   a - d , in some embodiments the measurement data may be stored within the communication modules  124   a - d  and subsequently recovered for post-job analysis following a cementing operation. More particularly, after the cementing operation is finished, a logging tool or device (not shown) may be sent downhole into the casing string  110  on a conveyance such as, but not limited to, wireline, slickline, electrical line, drill pipe, production tubing, coiled tubing, and the like. The logging tool may be configured to download the measurement data from each communication module  124   a - d  as it passes thereby within the casing string  110 . 
     In some embodiments, for example, the measurement data stored in the communications modules  124   a - d  may be transferred wirelessly to the logging tool as it passes the casing collars  116   a - d . The transmitters and receivers associated with each component may send and receive radio frequency (RF) signals, infrared (IR) frequency signals, or other electromagnetic signals. Any of a variety of modulation techniques may be used to modulate data on a respective electromagnetic or acoustic (or other) carrier wave(s). Alternatively, wired communications (including fiber optics) may also be performed to transfer the stored data. Communications protocols for managing communication are known, and may include IEEE 802.11, IEEE 802.3, USB-compatible, Bluetooth, etc. Such downloaded measurement data may provide the well operator with the drilling fluid, spacer fluid, and cement fluid properties measured during the cementing job at each casing collar  116   a - d  location and the final cement properties at such locations within the wellbore  106 . 
     In some embodiments, one or more of the casing collars  116   a - d  may be arranged above the expected top of cement within the annulus  112  and the associated sensors  120   a - d  may be configured to monitor pressure within the annulus  112  and/or the presence of hydrocarbons. In at least one embodiment, one or more of the casing collars  116   a - d  may be arranged just below a casing liner hanger (not shown), such as at the bottom of surface casing. Geothermal heat or heat emanating from formation fluids could expand the casing string  110  and/or the liner hanger and potentially damage or collapse the casing string  110  and/or the liner hanger. When the pressure within the annulus  112  exceeds a predetermined limit as detected by the associated sensors  120   a - d , a port or check valve (not shown) associated with the casing collar  116   a - d  may be configured to open to allow the pressure to escape into the casing string  110  and thereby relieve the pressure buildup within the annulus  112 . Once the pressure in the annulus  112  decreases past a critical level, the port or check valve may be configured to close once again. 
     Still referring to  FIG. 3 , but with continued reference to  FIG. 1 , in some embodiments, one or more of the casing collars  116   a - d  and/or an associated cement wiper plug  118  ( FIG. 1 ) may be used to measure and report the angular orientation of various downhole equipment (not shown) associated with the casing string  110 . Once the orientation of the downhole equipment is ascertained, such information may be transmitted to the surface  104  such that the downhole equipment may be oriented to a desired orientation within the wellbore  106 . Exemplary downhole equipment that may be oriented within the wellbore  106  using the present disclosure may include, but are not limited to, pre-perforated liners, sand screens, pre-milled windows, tubing exit whipstock-like muleshoes, and mandrels (e.g., gas-lift mandrels, etc.). 
     The sensors  120   a - d  in one or more of the casing collars  116   a - d  may include, for example, various accelerometers or gyroscopes arranged therein and configured to provide orientation information for the casing string  110 . In at least one embodiment, the sensors  120   a - d  used to measure orientation may be micro-electromechanical systems (MEMS), such as MEMS inertial sensors which may include various accelerometers, gyroscopes, and magnetometers. While the fluid  304  is being pumped or otherwise circulated within the wellbore  106 , the casing collars  116   a - d  may be configured to monitor and report the orientation of the casing string  110 . 
     In embodiments where an associated cement wiper plug  118  ( FIG. 1 ) is used with the casing collars  116   a - d , the orientation information may be fed to the cement wiper plug  118  which may transmit the information to the surface  104  via the pulser  132  ( FIG. 1 ). In other embodiments, the communication modules  124   a - d  may be configured to transmit the orientation information to the surface  104  either wired or wirelessly. In response to receiving the orientation information, a well operator may adjust the rotational direction of the casing string  110  such that the downhole equipment at issue is rotationally oriented as desired. 
     Referring to  FIG. 4 , with continued reference to  FIG. 1 , illustrated is an exemplary intelligence system  400  that may be used to measure the orientation of the casing string  110 , according to one or more embodiments. The intelligence system  400  may be used in conjunction with either the casing collar  116  or the cement wiper plug  118 , or a combination of both. The intelligence system  400  may include a power supply  402  that may provide power to at least a 3-axis accelerometer  404 . The accelerometer  404  may be in communication with a 3-axis gyroscope  406 . In some embodiments, the power supply  402 , the accelerometer  404  and the gyroscope  406  may each be arranged in or otherwise associated with the casing collar  116 , such as being arranged within the cavity  122  ( FIG. 1 ) of the casing collar  116 . 
     The intelligence system  400  may further be associated with the cement wiper plug  118 , which includes the power supply  128 , the computer hardware  130 , and the pulser  132 , as generally described above. In some embodiments, the power supply  402  of the casing collar  116  may power the computer hardware  130 . In other embodiments, however, the power supply  128  of the cement wiper plug  118  provides power to the computer hardware  130 , as described above. The power supply  128  also provides power to the pulser  132 . 
     The accelerometers  404  and gyroscopes  406  may be configured to communicate with the computer hardware  130  via an interface  408  and thereby provide the inputs for the computer hardware  130 . The computer hardware  130  may receive such data and determine the proper orientation of the downhole equipment at issue with respect to the Earth&#39;s gravity. Once the proper orientation is determined, this data may be sent to the pulser  132 , which transmits the data to the surface  104  via pressure pulses. The computer system  140  ( FIG. 1 ) at the surface  104  may receive and translate the pressure pulses into data that the well operator can consider and thereby make any needed orientation adjustments of the casing string  110 . 
     Embodiments disclosed herein include: 
     A. A well system that includes a casing string extending from a surface location within a wellbore, an annulus being defined between the casing string and the wellbore, a casing collar included in the casing string and having one or more sensors configured to measure at least one fluid property of a fluid present within the annulus, a cement wiper plug arranged within the casing string and communicably coupled to the casing collar such that measurement data obtained by the one or more sensors is conveyed to and received by the cement wiper plug, and a pulser included in the cement wiper plug and configured to transmit pressure pulses to the surface location, wherein the pressure pulses correspond to the measurement data received from the one or more sensors. 
     B. A method including arranging a casing string extending within a wellbore extending from a surface location, an annulus being defined between the casing string and the wellbore, measuring at least one fluid property of a fluid present within the annulus using one or more sensors associated with a casing collar included in the casing string, receiving measurement data obtained by the one or more sensors with a cement wiper plug arranged within the casing string and communicably coupled to the casing collar, and transmitting the measurement data to the surface location in the form of pressure pulses with a pulser associated with the cement wiper plug. 
     C. A method including arranging a casing string extending from a surface location within a wellbore, an annulus being defined between the casing string and the wellbore and one or more casing collars being arranged about the casing string along a length of the casing string, circulating a fluid through the casing string and the annulus, and measuring a fluid property of the fluid in the annulus with sensors associated with the one or more casing collars and thereby obtaining measurement data, wherein the fluid property comprises at least one of pressure, temperature, density, viscosity, pH, chemical composition, gas-cut, and presence of oil and/or gas within the fluid. 
     Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element 1: wherein the one or more sensors comprise a sensor selected from the group consisting of a temperature sensor, a pressure sensor, a strain gauge or sensor, a pH sensor, a density sensor, a viscosity sensor, a chemical composition sensor, an accelerometer, a gyroscope, magnetometer, a radiation sensor, an acoustic transponder, a sonic sensor, a mechanical sensor, a self/spontaneous potential sensor, and a nuclear detector or sensor. Element 2: wherein the casing collar further includes a communications module communicably coupled to the one or more sensors and configured to convey the measurement data to the cement wiper plug. Element 3: wherein the cement wiper plug further includes computer hardware communicably coupled to the pulser and configured to receive the measurement data from the communications module and operate the pulser in response thereto. Element 4: wherein the one or more sensors are spaced about a circumference of the casing string and configured to monitor the at least one fluid property of the fluid at a plurality of angles about the casing string. Element 5: wherein the fluid is at least one of a drilling fluid, a spacer fluid, a cement slurry, water, oil, petroleum, an emulsion of oil and water, and a formation fluid. Element 6 wherein the at least one fluid property of the fluid comprises a property selected from the group consisting of pressure, temperature, density, viscosity, pH, chemical composition, gas-cut, and presence of oil, formation water, salinity, radioactive tracers, salinity and nitride tracers, and/or gas within the fluid. 
     Element 7: wherein the fluid is at least one of a drilling fluid, a spacer fluid, a cement slurry, water, oil, petroleum, an emulsion of oil and water, and a formation fluid, and wherein measuring the at least one fluid property further comprises measuring at least one of pressure, temperature, density, viscosity, pH, chemical composition, gas-cut, and presence of oil, and/or formation water, salinity, radioactive tracers, salinity and nitride tracers, and/or gas within the fluid. Element 8: further comprising conveying the measurement data to the cement wiper plug using a communications module included in the casing collar and communicably coupled to the one or more sensors, and wherein transmitting the measurement data comprises operating the pulser to send the pressure pulses. Element 9: wherein the measurement data from the communications module is received with computer hardware included in the cement wiper plug, and wherein transmitting the measurement data further comprises sending a command signal to the pulser with the computer hardware. Element 10: further comprising receiving the pressure pulses with one or more surface sensors at the surface location, and translating the pressure pulses with a computer system communicably coupled to the one or more surface sensors. Element 11: wherein the fluid is drilling fluid, the method further comprising circulating a spacer fluid into the casing string and the annulus following circulation of the drilling fluid, measuring at least one fluid property of the spacer fluid in the annulus using the one or more sensors, receiving spacer fluid measurement data obtained by the one or more sensors with the cement wiper plug, transmitting the spacer fluid measurement data to the surface location with the pulser, and determining a volume of cement slurry required in the annulus by comparing the measurement data of the drilling fluid with the spacer fluid measurement data. Element 12: wherein measuring the at least one fluid property of the spacer fluid comprises measuring at least one of pressure, temperature, density, viscosity, pH, chemical composition, gas-cut, and presence of oil and/or gas within the spacer fluid. Element 13: wherein measuring the at least one fluid property of the spacer fluid further comprises stopping circulation of the spacer fluid after the spacer fluid is detected by the one or more sensors, and monitoring a property of the spacer fluid within the annulus while circulation is stopped and thereby determining whether the spacer fluid is being lost into a surrounding formation. Element 14: wherein the fluid is foam cement, and wherein measuring the at least one fluid property of the fluid further comprises measuring at least one of a quantity of a gas suspended in the foam cement, a quality of the gas suspended in the foam cement, and a density of the foam cement. 
     Element 15: further comprising storing the measurement data in a memory associated with the one or more casing collars, and downloading the measurement data to one of a logging tool or a bottom hole assembly introduced into the casing string following a cementing operation. Element 16: further comprising transmitting measurement data corresponding to the fluid property of the fluid to the surface location with a communications module included in at least one of the one or more casing collars. Element 17: wherein the sensors associated with at least one of the one or more casing collars are spaced about a circumference of the casing string, the method further comprising monitoring the fluid property of the fluid within the annulus at a plurality of angles about the casing string. Element 18: wherein the fluid property being measured by the sensors is pressure in the annulus, the method further comprising opening a check valve associated with at least one of the one or more sensors when the pressure in the annulus exceeds a predetermined limit, venting fluid pressure into the casing string through the check valve, and closing the check valve once the pressure in the annulus decreases below the predetermined level. 
     Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. 
     It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 
     As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” does not require selection of at least one item; rather, the phrase allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.