1. Field of the Invention
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.
2. Description of the Related Art
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.
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.
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).
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.
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.
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.
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.
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.
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.
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.
Referring to
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.
In the embodiment shown in
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.
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.
Referring now to
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.
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.
Referring to
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.
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.
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
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.
Referring now to
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.
Referring now to
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.
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.
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.
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Number | Date | Country | |
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20140158347 A1 | Jun 2014 | US |
Number | Date | Country | |
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61730420 | Nov 2012 | US |