Patent Abstract:
Methods and apparatus for sensing wellbore conditions in artificial lift wells using low profile sensors that are installed on down hole production equipment that makes them easier to install and retrieve. In one embodiment, low profile sensors are installed on a rod string making their insertion and removal much easier than it would be if they were mounted on production tubing. The sensors can be attached directly to the rod string or can be attached to a cable that is attached to the rod string. The sensors can transmit their data electrically through the cable or through the rod string. Alternatively, the sensors can transmit their data acoustically through the rod string.

Full Description:
RELATED APPLICATIONS 
       [0001]    This application claims the benefit under 35 U.S.C. 119(e) of U.S. Provisional Application Ser. No. 61/730,420, entitled “METHODS AND APPARATUS FOR SENSING IN WELLBORES” and filed on Nov. 27, 2012, the entire contents of which are incorporated by reference. 
     
    
     BACKGROUND OF THE INVENTION 
       [0002]    1. Field of the Invention 
         [0003]    Embodiments of the present invention generally relate to sensors for monitoring production fluid characteristics in an artificial lift well. More particularly, embodiments relate to a low profile sensor installable on a rotating or recipcocating string in a well rather than on a tubing string. 
         [0004]    2. Description of the Related Art 
         [0005]    Artificial lift wells depend on pumps or the like to move hydrocarbons, water, or other liquids in a wellbore to the surface. Typically, down hole pumps are used to pump the liquid(s) to the surface. For example, an electric submersible pump (ESP) can be lowered into the wellbore to a depth at which the liquid (e.g., oil) collects. The pump can be powered from the surface by a power conductor (e.g., a conductor cable) that runs to an electric motor located adjacent the pump. As the pump operates, the fluid is urged upwards in a string of production tubing toward the surface where it is collected. Conditions around the pump, like temperature and pressure, can be monitored during production. In wells using ESPs, sensors detecting temperature, pressure, and the like can be mounted on or proximate to the pump located at a lower end of production tubing. Also, the power conductor powering the pump can also provide power to the sensors and can provide a signal path for information from the sensors. ESPs are routinely pulled from wells for maintenance and replacement. The sensors which are mounted on, adjacent to, or proximate to the ESP are also returned to the surface when the ESPs are pulled, providing an opportunity to also inspect, maintain, and/or replace the sensors. 
         [0006]    In other applications in which down hole ESPs are not used, placing, powering, and replacing down hole sensors can be more difficult. For example, rod pumps (e.g., progressive cavity pumps) use a rod that extends from the surface to a rotor located down hole in the well. The rod can be rotated from the surface to turn the rotor in a stator down hole to pump the liquids to the surface. The rod pump does not have a down hole source of power for a sensor and the pump itself is smaller than an ESP, making the placement of a sensor difficult. Currently, in applications in which down hole pumps are not used, sensors are placed on production tubing that surrounds the rod string. As a result, replacement of the sensor requires the production tubing to be pulled. 
         [0007]    In other examples in which down hole ESPs are not used, a reciprocating pump can include a plunger and valve pump assembly that can be positioned down hole and a beam and crank assembly at the well surface that can create reciprocating motion in a sucker-rod string that connects to the down hole plunger and valve pump assembly. The pump contains a plunger and valve assembly to convert the reciprocating motion of the rod string to vertical fluid movement. As with rod pumps, the reciprocating pump does not have a down hole source of power for a sensor. Again, currently, sensors are placed on production tubing and therefore require the production tubing string to be removed to gain access to the sensor (e.g., to perform maintenance on the sensor or to replace the sensor). 
         [0008]    When operating progressive cavity pumps and reciprocating rod pumps, the rods can be pulled to inspect, repair, or replace a damaged pump or rotor. The ability to deploy the sensor on the rods (rather than on surrounding tubing) could prevent a costly heavy workover to remove the tubing. The ability to deploy the sensor on the rods can also provide an inexpensive means of temporary deployment of the sensor for well testing or flow optimization. 
         [0009]    What is needed is a more effective and efficient way to monitor wellbore conditions in the area of a down hole pump and a simpler way to remove sensors in the event they need replacement. 
       SUMMARY OF THE INVENTION 
       [0010]    The present invention generally provides methods and apparatus for sensing wellbore conditions in artificial lift wells using low profile sensors that are installed on down hole equipment that makes them easier to install and retrieve. 
         [0011]    According to one method, a low profile sensor can be installed on a rod string and then the rod string can be inserted into a well. While the rod string is being actuated to pump the well, the sensor can periodically take readings in the well. For example, the sensor can be taking pressure and temperature readings in the well. The sensor can transmit the readings up to the well surface. 
         [0012]    According to certain embodiments, an apparatus can include a low profile sensor that fits in an annulus between a rod string and one of production tubing and casing. The sensor can include a transmitter that transmits the sensed data to the well surface. The sensor can be attached to a cable that is attached to the rod string or the sensor can be attached directly to the rod string. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0013]    So that the manner in which the features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments. 
           [0014]      FIG. 1  is a partial cross-sectional view of a well with a progressive cavity pump; wherein an embodiment of a sensor is attached to a rotating rod string; 
           [0015]      FIG. 2  is a partial cross-sectional view of a well with a reciprocating rod pump, wherein an embodiment of a sensor is attached to a reciprocating rod string; 
           [0016]      FIGS. 3A-3C  illustrate an embodiment of a sensor attached to a cable; 
           [0017]      FIGS. 4A-4C  illustrate an embodiment of a sensor attached to and surrounding a rod string; 
           [0018]      FIG. 5A  is a partial cross-sectional view of a well with a rod string inserted therein, wherein an acoustic-transmitting sensor is attached to the rod string; 
           [0019]      FIG. 5B  is a block diagram of an embodiment of an acoustic-transmitting sensor and a receiver for receiving acoustically-transmitted signals; 
           [0020]      FIG. 6  is a partial cross-sectional view of a well with a rod string inserted there, wherein a plurality of sensors are attached to the rod string at different locations; and 
           [0021]      FIG. 7  is a flow chart that illustrates an embodiment of a method for operating a well using embodiments of the sensors described herein. 
       
    
    
     DETAILED DESCRIPTION 
       [0022]    In various embodiments, a low-profile sensor can be installed on a rod string to measure parameters in a well bore near a pump being operated by the rod string. The sensors enable a well operator to monitor the health of the pump and/or the production capability of the well, for example. 
         [0023]    Referring to  FIG. 1 , in one embodiment, a low profile sensor  118  can be installed on a rotating pumping rod string  106  that operates a progressive cavity (“PC”) pump  108 ,  110  at a lower end of the pumping rod string  106 . A progressive cavity pump, including a rotor  108  and a stator  110 , is a type of positive displacement pump and is also known as a progressing cavity pump, eccentric screw pump or cavity pump. The PC pump transfers fluid by means of the progress, through the pump, of a sequence of small, fixed shape, discrete cavities, as its rotor is turned. This progress of fixed-shape cavities leads to the volumetric flow rate being proportional to the rotation rate (bidirectionally) and to low levels of shearing being applied to the pumped fluid. Hence, these pumps have application in fluid metering and pumping of viscous or shear-sensitive materials. The cavities taper down toward their ends and overlap with their neighbours, so that, in general, no flow pulsing is caused by the arrival of cavities at the outlet, other than that caused by compression of the fluid or pump components. 
         [0024]    The pumping rod string  106  can be positioned in a well  102  in the earth  130  inside of casing  104 . In some embodiments, the well  102  can also include one or more production tubing strings between the pumping rod string  106  and the casing  104 . Perforations  112  in the casing  104  (and any production tubing strings) enable the oil, water, and/or natural gas to enter into the casing  104  (and any production tubing strings). The pumping rod string  106  can be positioned in the well  102  such that the rotor  108  and stator  110  are positioned near the perforations  112  at the oil, water, and/or natural gas deposit  132 . Then, the pumping rod string  106  can be rotated such that the rotor  108  of the PC pump is rotated in the stator  110 . The resulting rotation displaces the water, oil, and/or natural gas upwards toward the surface  134  of the well  102 . 
         [0025]    In the embodiment shown in  FIG. 1 , the rotating pumping rod string  106  includes a sensor cable  120  extending from the sensor  118  towards the surface  134  of the well  102 . As shown in  FIGS. 3B and 3C , in various embodiments, the cable  120  can pass through the sensor  118 . In such embodiments, an end of the cable  120  below the sensor  118  can be attached to the pumping rod string  106 . The cable  120  (e.g., tubing encapsulated conductor (TEC) cable) can provide power to the sensor and can and transmit information from the sensor  118  to a receiver  124  at the surface  134  of the well  102 . The cable  120  and sensor  118  can rotate with the pumping rod string  106 . The well  102  can include a coupling  114 ,  116  that permits electrical and data communication between the sensor cable  120  and sensor  118  rotating with the rod string and a stationary housing there around (e.g., casing  104 ). For example, the coupling can include a rotating disk  114  that is connected to the pumping rod sting  106  and is made of copper, brass, or another conductive material. The pumping rod string  106  can be electrically coupled to the rotating disk  114  such that information from the sensor  118  that is transmitted via the cable  120  and the pumping rod string  106  can pass onto the rotating disk  114 . Alternatively, the cable  120  can be directly attached and electrically coupled to the rotating disk  114 . The coupling can also include a stationary disk  116  that can be mounted to a stationary structure, such as the casing  104 , for example. The stationary disk  116  can also be made of copper, brass, or another conductive material. When the rotating pumping rod string  106  is placed in the well  102 , the rotating disk  114  can be in sliding contact with the stationary disk  116 . As a result, an electrical connection can be formed between the rotating disk  114  and the stationary disk  116  such that electrical signals can be passed from the sensor  118  to the stationary disk  116  via the rotating disk  114  and power can be transmitted from the stationary disk  116  to the sensor  118 . At the surface, another segment of cable  120  can carry sensor signals from the stationary disk  116  to a receiver  124 . As will be described in greater detail below, in alternative embodiments, the sensor  118  can be arranged around and attached to the rotating rod  106 , eliminating the cable  120 . In such embodiments, if the rod string  106  includes a conductive material, sensor signals can be transmitted from the sensor  118  through the pumping rod string  106  to the rotating disk  114  and onto the stationary disk  116 . 
         [0026]    In alternative embodiments, an electrical connection between the rotating pumping rod string  106  and a stationary housing (e.g., the casing  104 ) can be accomplished by fixing a first outer ring electrode to the casing  104  and a first inner ring electrode to the rotating pumping rod string  106  for rotation therewith. An annular gap can be formed between the first outer ring electrode and the first inner ring electrode. The first outer ring electrode and the first inner ring electrode form a first connector gap in fluid communication with the annular gap. In an additional optional step, a second outer ring electrode can be fixed to the casing  104  and a second inner ring electrode to the pumping rod string  106  for rotation therewith. The second outer ring electrode and the second inner ring electrode can form a second connector gap in fluid communication with the annular gap. A fluid may be supplied in the annular gaps to complete an electrical connection between the rotating inner ring electrode(s) and the stationary outer ring electrode(s). An object of the arrangement is to provide an electrical connection between a rotating structure and another structure that may be stationary or rotating in a down hole tool. Such connections are well known in the art and one further example is shown in U.S. Pat. No. 8,162,044 which is incorporated herein by reference in its entirety. 
         [0027]    In the event the progressive cavity pump needs to be inspected, repaired, or replaced, the pumping rod string  106  can be pulled out of the well  102 . The sensor  118  (and cable  120 , when used) will also be pulled out of the well  102  as a result, providing an opportunity to inexpensively inspect, repair, and/or replace the sensor  118  too. 
         [0028]    Referring now to  FIG. 2 , in another embodiment, a low profile sensor  218  can be installed on a reciprocating pumping rod string  206  in a beam pump  208 ,  210 . The reciprocating pumping rod string  206  can be driven up and down in a well  202  by a pump jack  230 . In this embodiment, the well  202  includes casing  204 , production tubing  205 , and the reciprocating pumping rod string  206 . Oil, water, and/or natural gas from an underground reservoir  132  can pass through the casing  204  and/or production tubing  205  through perforations  212 . A series of check valves  208  and  210 , in combination with a plunger, lift the oil, water, and/or natural gas from the pump towards the surface  134 . One or more rod guides  207  can be arranged on the reciprocating pumping rod string  206  to align the reciprocating rod  206  within the well bore  202 . Similarly to  FIG. 1 , a low profile sensor  218  can be attached to a cable  220  (e.g., TEC) and reciprocate up and down with the reciprocating pumping rod string  206 . The cable  220  can extend up toward the surface  134 . The cable  220  can pass through slots or apertures in the rod guides. Often, in a pump jack  230  arrangement, a reciprocating rod, such as reciprocating pumping rod string  206  will pass through a seal at the well head  222 . A top portion of the reciprocating pumping rod string  206  can be hollow and can include two apertures  214  and  216 . The lower aperture  214  can be positioned in the well  202  below the seal and the upper aperture  216  can be positioned above the well head  222  and above the seal. As shown, the cable  220  can pass into the hollow portion of the reciprocating pumping rod string  206  through the lower aperture  214  and then exit out of the hollow portion through the upper aperture  216 . Routing the cable  220  through the hollow portion of the pumping rod string  206  via apertures  214  and  216  can avoid problems caused by attempting to run the cable  220  through the seal in the well head  222 . After passing out of the well head  222 , the cable  220  can then lead to a receiver  224  where data from the sensor  218  can be collected. 
         [0029]    As will be described in greater detail below, in certain embodiments, the sensor  218  can be attached directly to the reciprocating pumping rod string  206 . For example, the sensor  218  can be clamped around the pumping rod string  206 . If the reciprocating pumping rod string  206  includes a conductive material, then power can be transmitted to the sensor  218  via the pumping rod string  206  and signals can be transmitted from the sensor  218  via the pumping rod string  206 . A cable can be attached to a top end of the reciprocating pumping rod string  206  to pass the signal from the pumping rod string  206  to the receiver  224 . 
         [0030]    In the event the reciprocating pump needs to be inspected, repaired, or replaced, the pumping rod string  106  can be pulled out of the well  202 . The sensor  218  (and cable  220 , when used) will also be pulled out of the well  202  as a result, providing an opportunity to inexpensively inspect, repair, and/or replace the sensor  218 . 
         [0031]      FIGS. 3A-3C  illustrate an embodiment of a low profile sensor  310  attached to a cable  300 . Referring to  FIG. 3A , a top view of the sensor  310  and cable  300  shows that the sensor  310  can be coaxially arranged around the cable  300 . In various embodiments, an outer diameter of the cable  300  can be three quarters of an inch and the outer diameter of the sensor  310  can be two inches, for example.  FIG. 3B  illustrates a side view of a half of the outer casing  302  of the sensor  310 . The sensor  310  can include two casings  302  that clamp around the cable  300 . The casings  302  can be held together by a series of screws  308 , bolts, clips, adhesives, or the like. Referring now to  FIG. 3C , a cross-sectional view of the sensor  310  shows an interior cavity  306  that can house the sensor components. For example, the interior cavity  306  can house a pressure sensor, a temperature sensor, memory for storing transducer readings, a data transmitter, a computer processor for recording transducer readings to memory and for transmitting readings from memory. At least some of the sensor components can include micro-electrical-mechanical systems (MEMS). In certain embodiments, the pressure sensor can include a low profile pressure sensor capable of measuring pressures between 0 and 3,000 pounds per square inch (psi) and that is capable of withstanding temperatures up to 125° C. In certain embodiments, the temperature sensor can include a resistive temperature detector capable of measuring temperatures between 0 and 125° C. In certain embodiments, a printed circuit board that enables signals from the pressure sensor and RTD to be processed and transmitted through the transmission conduit to the surface receiver (e.g., receiver  124  or  224 ). In certain embodiments, the interior cavity  306  of the sensor  310  can also include a power supply that can power the sensor components. For example, the power supply can comprise a battery (e.g., a lithium ion battery) and/or a capacitor. The casing  302  of the sensor  310  can include one or more ports  304  through which the sensor can detect aspects (e.g., temperature and pressure) of the liquids being pumped by the well. 
         [0032]      FIGS. 4A-4C  illustrate an embodiment of a low profile sensor  410  attached to a rotating or reciprocating pumping rod string  400 . The pumping rod string  400  is illustrated as being hollow, but it can also be solid. In various embodiments, an outer diameter of the pumping rod string  400  can be 2.38 inches and an outer diameter of the casing  402  can be 3.88 inches, for example. Referring to  FIGS. 4B and 4C , the sensor  410  can include an interior cavity  406  that houses sensor components, such as a pressure transducer, a temperature transducer, memory for storing transducer readings, a data transmitter, a computer processor for recording transducer readings to memory and for transmitting readings from memory. The cavity  406  can also include a power supply, such as a battery or capacitor. The casing  402  of the sensor  410  can include one or more ports  404  through which the sensor can detect aspects (e.g., temperature and pressure) of the liquids being pumped by the well. 
         [0033]    Referring to  FIGS. 3A-3C  and  4 A- 4 C, the sensor components will, in certain embodiments, be positioned in the cavities  306  and  406  in the sensor casings  302  and  402 , respectfully. The sensor components can be distributed between the two halves and the halves can then be filled Polycast RTV-793 high thermally conductive silicone with high dielectric strength and high tensile strength. In one example, the two halves can be molded to the tubing and cured for 24 hours before assembly and testing. In certain other embodiments, the sensor components can be positioned in a first half of the cavities  306  and  406  and a power supply can be positioned in the second half of the cavities  306  and  406 . 
         [0034]    The basic operation of down hole sensors, such as sensors  310  and  410 , described above, and their components are well known. An example of such sensors includes the FORTRESS PCP-4000 down hole progressive pump sensor made by Sercel-GRC Corporation, the specifications of which are incorporated by reference in their entirety. 
         [0035]    As described above, in certain embodiments, a cable, such as cable  300  can provide communication and power to the sensor  310 . As also described above, in certain other embodiments, the sensor  310  can be powered by an on-board power supply (e.g., an on-board lithium battery) capable of powering the system for the normal life of the artificial lift well or at least for a period of time corresponding to a scheduled maintenance interval that requires the rod string and/or pump to be removed from the well. Incorporating an on-board power supply into the sensor can eliminate or minimize the amount of power that must be supplied to the sensor via a cable. As a result, a smaller-diameter cable that only has to carry sensor signals can be used. In certain other embodiments, an on-board power source in the sensor can operate in conjunction with a powered cable to provide power to the sensor. For example, a smaller-diameter cable can be connected to the sensor that only provides a fraction of the power demand required by the sensor when the sensor is actively recording and/or transmitting sensor readings. However, the power provided by the cable can be sufficient to charge the on-board power supply (e.g., a battery or capacitor) during periods between sensor readings. The on-board power supply, alone or in combination with the cable, can then power the sensor when the sensor is actively recording and/or transmitting sensor readings. 
         [0036]    In other embodiments, a sensor system can communicate data to the surface using acoustic telemetry rather than electrical signals. Sending and receiving down hole data using telemetry is known in the art and an example of the technology is described in US Publication No. 2008/0030365, the contents of which are incorporated herein by reference in their entirety. Referring to  FIG. 5A , a sensor  506  with an on-board power source can be attached to a pumping rod string  504  inside of production tubing (and/or casing)  502  in a well bore  500 . The sensor  506  can include an acoustic transmitter (e.g., a piezoelectric transducer and/or speaker) that can emit acoustic signals. In certain embodiments, the acoustic transmitter can be coupled to the pumping rod string  504  such that it transmits the acoustic signal (i.e., the acoustic telemetry) into the pumping rod string  504 . The acoustic signal then propagates along the pumping rod string  504  to a microphone  512  at the surface  134  of the well  500 . The microphone  512  can then pass the received acoustic signal to a receiver  516  via a surface cable  514 . The receiver  516  can log sensor readings. By transmitting the sensor data acoustically and powering the sensor with an on-board power supply, a cable (e.g., TEC cable) connecting the sensor to the surface can be eliminated, thereby reducing costs, increasing the ease of deploying sensors into wellbores, and increasing the reliability of data transmission (e.g., that can otherwise be interrupted by damage to the cable). 
         [0037]    In certain instances, the sensor  506  may not have sufficient power to transmit an acoustic signal to the surface. In such instances, one or more repeaters can be arranged between the sensor  506  and the microphone  512  to boost the strength of the acoustic signal. 
         [0038]    Referring now to  FIG. 5B , a block diagram illustrates an embodiment of modules, systems, components, and the like in the sensor  506 , microphone  512 , and receiver  516  that gather, transmit, interpret, and store acoustically-transmitted telemetry. The acoustic-transmitting sensor  506  can gather sensor data  520  and pass the data into an encoder  522 . The encoder can translate the sensor data into a computer-readable format. For example, the encoder  522  can translate the sensor data  522  into a 16-bit binary format. The encoded data can then be sent to a modulator  524  that can generate a modulated waveform that can transmit the encoded data. For example, the modulated waveform can comprise a frequency modulated waveform wherein “zeros” of an encoded binary data packet can be represented by a first frequency and wherein “ones” of the encoded binary data packet can be represented by a second frequency. The modulator  524  can pass the modulated waveform to a transducer  526  that can transmit the modulated waveform as an acoustic signal  528  to the rod string, as described above. For example, the transducer  526  can transmit the modulated waveform onto a steel surface of the rod string  504  or tubing such that the modulated waveform can propagate along the rod string  504  or tubing to a data link (e.g., the microphone  512 ) at the surface  134  of the well  500 . This means of transmission is most feasible when the data transmissions are limited to small packets of data, such as a batch of pressure and temperature readings. 
         [0039]    After propagating along the pumping rod string, the acoustic signal  528  can reach a data link  512  (e.g., a microphone) coupled to the receiver  516 . The data link  512  can transmit the acoustic signal  528  to a decoder that converts the acoustic signal  528  into an electrical modulated waveform signal. The electrical modulated waveform signal can then be passed to a demodulator, which can extract the signal information (e.g., the binary data packet) from the modulated waveform. The extracted signal information can then be stored in memory  534 . 
         [0040]    Referring now to  FIG. 6 , in certain embodiments, multiple sensors  606 ,  608 ,  610 , and  612  can be deployed at intervals along a pumping rod string  604  in a well  600 .  FIG. 6  shows an embodiment in which four sensors are deployed at different locations along a pumping rod string in a well bore  602 . For example, each sensor may be deployed to measure pressure and temperature at a different producing zone within a well (i.e., at different depths and/or locations at which oil, water, and/or natural gas may be found). In addition to measuring pressure and temperature data at its location in the well  600 , in certain embodiments, the sensor  606  nearest the surface  134  can act as a host for remaining sensors  608 ,  610 , and  612 . The host sensor  606  can receive pressure and temperature data signals from the remaining sensors  608 ,  610 , and  612  and re-transmit the data signals to a receiver at the well head  620 . Furthermore, in certain embodiments, each sensor can re-transmit data from sensors beneath it to sensors above it. For example, sensor  610  can receive and re-transmit data from sensor  612 . Similarly, sensor  608  can receive and re-transmit data from sensor  610  (which can include the data re-transmitted from sensor  612 ). 
         [0041]    In certain embodiments, the sensors  606 ,  608 ,  610 , and  612  can share a common cable or pumping rod string (e.g., TEC tubing) such that each sensor receives power from the cable or pumping rod string and also transmits data on the cable. In various other embodiments, the sensors  606 ,  608 ,  610 , and  612  can transmit data acoustically along the pumping rod string  604 , as described above. In either embodiment, the signals from different sensors can be distinguished from the signals of remaining sensors. For example, each sensor could transmit its signal at a different frequency, enabling a receiver at the wellhead  620  to distinguish each of the different sensor signals. As another example, different sensors can be configured to transmit data signals at different times. For example, sensor  606  can be configured to transmit its data at the top of each hour (e.g., 1:00 PM, 2:00 PM, etc.), sensor  608  can be configured to transmit its data at a quarter past each hour (e.g., 1:15 PM, 2:15, PM), sensor  610  can be configured to transmit its data at a half past each hour (e.g., 1:30 PM, 2:30 PM, etc.), and sensor  612  can be configured to transmit its data at a quarter before each hour (e.g., 1:45 PM, 2:45 PM, etc.). In such a configuration, the receiver at the well head  620  can identify the sensor associated with a particular signal based on the time the signal is received. 
         [0042]      FIG. 7  illustrates a flow diagram of an embodiment of a method  700  for operating a well according to embodiments of the present invention. After a well bore has been drilled (block  702 ), a casing can be installed in the well bore (block  704 ). Optionally, production tubing can be installed within the casing (block  706 ). After the production tubing is installed, a well can be ready for production (e.g., pumping of oil, water, and/or natural gas from an underground deposit to the surface). A down hole sensor, such as any of sensors  118 ,  218 ,  310 ,  410 ,  506 , or  606 ,  608 ,  610 , and  612 , described above, can be attached to a pumping rod string that drives a pump to pump the oil, water, and/or natural gas out of the well (block  708 ). For example, the pumping rod string can rotate to drive a rotor of a progressive cavity pump or can reciprocate to drive a plunger valve assembly pump. After the sensor(s) is (are) attached to the pumping rod string, the pumping rod string can be lowered into the well bore (block  710 ). After being lowered into the well bore, the pumping rod string can be operated (e.g., rotated or reciprocated) to operate the pump in the well (block  712 ). As the pumping rod string is operated, the sensor(s) can periodically transmit information about aspects of the well (e.g., pressure and temperature data) to a data receiver at the well surface (block  712 ). Occasionally, the pumping rod string may need to be removed from the well for maintenance (block  714 ). The sensor(s) will also be removed from the well when the pumping rod string is removed, providing an opportunity for the sensor(s) to be inexpensively inspected, maintained, and/or replaced. 
         [0043]    While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Technology Classification (CPC): 4