Patent Grant
11339648
The invention relates generally to the operation of downhole equipment, and more particularly to systems and methods for communication between equipment such as surface equipment and downhole equipment installed in a well using conductive rods, tubulars and/or casings to form an electrical circuit.
Gas wells often require the use of an artificial lift system to remove water or other well fluids from the well when the fluid level rises to a level that impedes gas production. Most production systems in coal seam gas (CSG) wells use progressive cavity pumps (PCPs) to remove water from CSG wells and maintain a wellbore water level that is below a desired maximum level. Some CSG wells use rod lift systems (RLSs) as an alternative to PCPs to remove water from the wells.
CSG well operation is intermittent in nature due to changes in the water level in the well. In other words, gas is produced for some interval of time, then water is produced for an interval, then gas is produced again, and so on, alternating between a gas production phase and a water production phase. This is because, during the gas production phase, the gas flows in the annular space between casing and PCP pump assembly, but water in this annular space may rise to a level that impedes the gas flow.
As the gas is being produced, the pump system (PCP or RLS) is normally turned off, and the water level in the well may rise. When the water level is higher than desired, the pump is turned on to remove water (typically with coal fines) from the well and thereby reduce the water level in the well. The PCP is commonly turned on when water in the annular space in the well reaches a certain hydrostatic head or pressure limit. Conventionally, this hydrostatic head or pressure is measured by a downhole gauge which is coupled by wires to the surface so that it can receive power and transmit (or receive) data. A surface controller for the PCP system will operate the system until the hydrostatic head of the water in the well is reduced to a desired value. At this point, the PCP system is shut off, and gas production resumes, with gas flowing through the annular space.
The most common failure mode of PCP systems in CSG wells is stator burn-up which is caused by pumping off the water so that the pump runs dry. This may occur as the rate at which water enters the well declines after a few months of production. The pumping off of the water may result from a problem such as a damaged electrical cable or poor connectivity between the downhole pressure gauge and the surface controller, which may cause a failure of the downhole pressure gauge to provide an appropriate signal to the surface controller to indicate a reduced water level. Thus, the PCP system would continue to operate, even during the gas production phase. As the water is pumped off, the gas would enter the PCP system, undergo compression due to the positive displacement feature of the PCP system, and overheat the stator. The overheating may then lead to thermal degradation of the stator material (rubber), compromising the pump integrity.
The failure of the pump system introduces additional equipment and workover costs, which may amount to hundreds of thousands of dollars. The costs may be incurred because, for example, the well may have to be killed in order to re-complete the well if the wired gauge line cannot be snubbed out due to well control. The well may also potentially lose months of production, as the PCP would need to be brought online to dewater the well again in order for gas to flow in the well.
It is therefore very important to communicate information regarding downhole conditions (e.g., water level) to the control equipment at the surface of the well (e.g., controlling the operation of a pump to avoid pump-off). As noted above, problems with conventional communication systems between the downhole equipment and the surface equipment may experience poor or failed connectivity as a result of damaged electrical cables, which may lead to damage or failure of the downhole equipment (e.g., stator burn-up), which may in turn result in lost production, as well as increased costs associated with repairs and re-starting production. It would therefore be desirable to provide systems and methods which reduce or eliminate the problems associated with conventional wired communication systems.
Embodiments disclosed herein provide systems and methods for providing wireless communications between a downhole gauge or other tool that is positioned in a well bore and a unit at the surface of the well. Embodiments use toroidal coils that are positioned around a component such as a pump rod that extends axially in the well, where a data signal applied to one toroidal coil induces currents in the axially extending component, and these currents induce a voltage in another toroidal coil which can be sensed to receive the data.
One embodiment comprises a system for communicating between surface equipment and a downhole tool installed in a well. The system includes first and second structural members of a well completion which are connected by first and second electrical couplings to form a first electrical circuit. A first toroidal transformer is positioned around the second structural member at an axial location which is between the first and second electrical couplings. A second toroidal transformer is also positioned around the second structural member, but is positioned at a different axial location between the first and second electrical couplings. A transmitter is coupled to the first toroidal transformer and is configured to generate a data signal (which in one embodiment has a frequency of between 30 Hz and 300 Hz), where when the data signal is applied to the first toroidal transformer. This causes a corresponding electrical current to be induced in the first electrical circuit, which then induces the data signal on the second toroidal transformer. A receiver is coupled to the second toroidal transformer in order to receive the data signal induced on the second toroidal transformer. The transmitter and receiver and the corresponding toroidal coils may be arranged to transmit data from the surface equipment to the downhole tool, or from the downhole tool to the surface equipment. The transmitter and receiver may be components of corresponding transceivers, and the system may be capable of transmitting data bidirectionally. The system may also include one or more additional toroidal coils and corresponding transceivers so that data may be communicated to/from multiple different locations in the well.
In one embodiment, the first structural member comprises a conductive casing installed in the well, and wherein the second structural member comprises a conductive tubular installed in the well within the casing. In another embodiment, the first structural member comprises the casing of the well and the second structural member comprises a conductive pump rod coupled between a drive system and a pump installed in the well. In yet another embodiment, the first structural member comprises a conductive tubular installed in the well, and the second structural member comprises the conductive pump rod. In some embodiments, there is an annular space between the first and second structural members, where a first portion of the annular space is filled with a well fluid and a second portion of the annular space is filled with air. In one embodiment, the first portion of the annular space is no more than 60 feet in length and the second portion of the annular space is at least 100 feet in length.
An alternative embodiment comprises a method implemented in a well having first and second structural members of a well completion system electrically coupled to form a first electrical circuit, the well completion system including first and second toroidal transformers positioned at axially different locations around one of the structural members with a transmitter coupled to the first toroidal transformer and a receiver coupled to the second toroidal transformer. The method includes generating a first voltage embodying a data signal at the transmitter and applying the first voltage to the first toroidal transformer. The first toroidal transformer induces a current corresponding to the data signal in the structural members (e.g., a pump rod or tubular) around which it is positioned. This induces in the second toroidal transformer a second voltage embodying the data signal. The second voltage is provided to the receiver and the receiver extracts the data signal from the second voltage.
In one embodiment, the method includes making measurements using equipment positioned downhole in a well, generating the data signal in dependence on the measurements, and providing the data signal to the transmitter. The data corresponding to the measurements may be stored in a data store prior to being transmitted. The measurements may comprise measurements of operating conditions at the location of an electric submersible pump installed in the well. Data may be communicated between the first and second toroidal coils, as well as additional toroidal coils positioned along the length of the structural member.
Numerous other embodiments are also possible.
The drawings accompanying and forming part of this specification are included to depict certain aspects of the invention. A clearer impression of the invention, and of the components and operation of systems provided with the invention, will become more readily apparent by referring to the exemplary, and therefore non-limiting, embodiments illustrated in the drawings, wherein identical reference numerals designate the same components. Note that the features illustrated in the drawings are not necessarily drawn to scale.
While the invention is subject to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and the accompanying detailed description. It should be understood, however, that the drawings and detailed description are not intended to limit the invention to the particular embodiment which is described. This disclosure is instead intended to cover all modifications, equivalents and alternatives falling within the scope of the present invention as defined by the described embodiments. Further, the drawings may not be to scale, and may exaggerate one or more components in order to facilitate an understanding of the various features described herein.
The invention and the various features and advantageous details thereof are explained more fully with reference to the non-limiting embodiments that are illustrated in the accompanying drawings and detailed in the following description. Descriptions of well-known starting materials, processing techniques, components, and equipment are omitted so as not to unnecessarily obscure the invention in detail. It should be understood, however, that the detailed description and the specific examples, while indicating some embodiments of the invention, are given by way of illustration only and not by way of limitation. Various substitutions, modifications, additions, and/or rearrangements within the spirit and/or scope of the underlying inventive concept will become apparent to those skilled in the art from this disclosure.
The invention and the various features and advantageous details thereof are explained more fully with reference to the non-limiting embodiments that are illustrated in the accompanying drawings and detailed in the following description. Descriptions of well-known starting materials, processing techniques, components, and equipment are omitted so as not to unnecessarily obscure the invention in detail. It should be understood, however, that the detailed description and the specific examples, while indicating some embodiments of the invention, are given by way of illustration only and not by way of limitation. Various substitutions, modifications, additions, and/or rearrangements within the spirit and/or scope of the underlying inventive concept will become apparent to those skilled in the art from this disclosure.
As described herein, various embodiments of the invention comprise systems and methods for providing communications between equipment installed downhole in a well and equipment at the surface of the well. These embodiments may allow for the downhole tools to wirelessly communicate data to (and receive data from) the surface equipment. In one exemplary embodiment, downhole equipment such as a submersible pump is installed in a cased well. The submersible pump is coupled to a tubular through which fluid is pumped to the surface of the well. A wireless communication system uses one toroidal coil to induce currents in the tubular and another toroidal coil to sense the current near the submersible pump. Data is communicated from the first coil, through the tubular, to the second coil.
The wireless communication system uses what may be referred to herein as a toroid coupled line (TCL) to enable data communication between the surface equipment and the downhole equipment. This system uses a first toroidal transformer which is positioned around the tubular at or near the pump, and a second toroidal transformer which is positioned around the tubular at or near the surface equipment. Transceivers are coupled to each of the toroidal transformers. One of the transceivers (e.g., at the pump) generates electrical signals that are applied to the corresponding toroidal transformer, thereby inducing current in the tubular. The tubular is electrically coupled to the casing of the well in order to complete a circuit through which the induced current flows. The current in the tubular in turn induces current in the other transformer, which is detected by the corresponding transceiver. The transceiver interprets the detected current to identify the data embodied in the signal and provides this data as an output to control equipment, a user display, or some other device.
It should be noted that the TCL makes use of one electrically conductive component that is substantially concentrically positioned within another, tubular electrically conductive component. In some embodiments, the inner component is a tubular and the outer component is the well casing. In other embodiments, inner component may be a rod which drives the pump, and the outer component may be the well casing or a tubular.
Referring to
As shown in
A wireless gauge 160 is installed downhole in the well near pump 130. Wireless gauge 160 in this embodiment is configured to monitor the pressure of the water in the well and to communicate this information to a controller 170 at the surface of the well. Surface controller 170 is coupled to drive 140 and prime mover 145 and is configured to cause these units to drive rod 150 and pump 130 as needed to remove water from the well. When the water level in the well is low enough to allow gas to be produced, surface controller 170 controls driver 140 and prime mover 145 to stop, suspending operation of pump 130 so that pump off conditions do not cause overheating of pump 130. (“Water”, as used here, should be construed to include brine or other fluids that may be found in the well.)
In this embodiment, wireless gauge 160 has a transceiver that is coupled to a toroidal coil 180 which is mounted around tubing 110. When it is necessary to transmit data from gauge 160 to controller 170, an electrical signal that embodies the data is generated and applied to coil 180, causing current to flow through the coil. The magnetic fields generated by the current flowing through the coil induces a corresponding current in tubing 110. This current flows through tubing 110 and itself induces current in a second toroidal transformer 190 which is positioned at the upper end of the tubing. (It should be noted that tubing 110 is electrically coupled to the well casing 120 just below toroidal transformer 180, and just above toroidal transformer 190, so that tubing 110 and casing 120 form a complete circuit through which current can flow.) the current in toroidal transformer 190 is sensed by a transceiver coupled to surface controller 170, which extracts the data embodied in the current and processes or uses the data to control pump 130. In a similar manner, surface controller 170 can communicate data through toroidal transformer 190, tubing 110 and toroidal transformer 180 to a transceiver which provides this data to pump 130.
Referring to
It should be noted that, although this exemplary embodiment describes a pump that uses a rod to drive the pump, where the rod serves as one conductor of the pair of coaxial conductors, alternative embodiments may use the production tubing and the casing of the well as the coaxial conductors.
A wireless gauge system 240 is positioned near pump system 220. Wireless gauge system 240 includes a gauge subsystem 242 and a transmitter subsystem 244. Gauge subsystem 242 may include pressure and temperature sensors, as well as any other types of sensors that might be desirable. Gauge subsystem 242 receives power from a downhole power subsystem 246. Power subsystem may use various means to generate power downhole, or may receive power via the coaxial conductors 230. The generated or received power may be stored in a battery or other energy store of the power subsystem. Power subsystem 246 is also coupled to transceiver subsystem 244. Transceiver subsystem 244 receives data from gauge subsystem 242 and wirelessly transmits this data (using power from power subsystem 246) via coaxial conductors 230 to a transceiver 252 of surface control system 250. The received data can then be used by a drive controller 254 of the surface control system 250 to control the operation of drive 210.
Gauge system 240 is wireless. In other words, the system does not include wires or cables through which data can be communicated from the gauge to the surface equipment. Likewise, there are no wires or cables through which power can be provided to the gauge. Gauge system 240 therefore includes a local energy store to provide its own power to gauge subsystem 242 and transmitter subsystem 244. In some embodiments, the subsystem may include components for local generation of power (e.g., from frictional heating), or the power may be supplied wirelessly through the coaxial conductors (e.g., rod and production tubing), as will be discussed in more detail below.
Referring to
Referring to
One exemplary type of communication subsystem uses a toroid coupled line (TCL) to wirelessly communicate data from the gauge subsystem to the surface control system. Rather than using wires or cables which may be damages in the harsh downhole environment, the TCL subsystem uses the electrically conductive pump rod and production tubing as a transmission line. The transmitter uses a toroidal coil to induce electrical currents that flow through the rod and production tubing (which are electrically coupled to form a complete circuit). The transmitter generates an AC signal which is applied to the toroidal coil, which in turn induces current in the rod and production tubing, with one serving as the electrical transmission pathway and the other serving as the electrical return pathway. A second toroidal coil is provided at the upper ends of the rod and production tubing to sense the induced currents and to provide a corresponding electrical signal to the surface control system.
This is depicted in
As depicted in these figures, a downhole transceiver 510 which is coupled to the gauge and power subsystems generates a signal that is provided to toroidal coil 520. In one embodiment, the transceiver and toroidal coil are positioned in proximity to an pump (e.g., ESP) which is installed in the well. These signals induce currents in pump rod 530 and production tubing 540. Rod 530 and tubing 540 are electrically coupled by conductors 550, 555 to form a complete circuit or pathway for the induced currents. Conductor 550 electrically connects the rod and production tubing below transmitting toroidal coil 520, while conductor 555 electrically connects the rod and production tubing above a second toroidal coil 560 which is coupled to a transceiver 570. Toroidal coil 560 and transceiver 570 in this embodiment are positioned at the surface of a well (e.g., the coil may be incorporated into a wellhead). The currents that are induced in the rod and production tubing by toroidal coil 550 are sensed by second toroidal coil 560. In other words, the currents in the rod induce an electrical potential in the second toroidal coil. The potential of second toroidal coil 560 is applied to transceiver 570, thereby communicating the transmitted signal to the transceiver. Because no conductors other than the pump rod and production tubing are needed (i.e., no conventional wires or cables are required), this system is considered to be “wireless” for the purposes of this disclosure.
It should be noted that a third coil (580) and corresponding transceiver (582) are shown in
Referring to
It should also be noted that the system can operate bidirectionally, with transceiver 570 generating data signals and applying the signals to toroidal coil 560, which induces current in rod 530, in turn inducing current in coil 520 that can be sensed, decoded and used as needed by the downhole tool.
Referring to
In another alternative embodiment, the rod can be used in conjunction with the well casing as a return pathway, or the production tubing and casing can be used as transmission and return pathways. In yet another embodiment, a coaxial transmission line can be formed by two of: the rod, the production tubing, and the well casing.
Referring to
In this embodiment, a downhole tool first collects data (810). For example, the downhole equipment may include a sensor which measures hydrostatic pressure at a downhole pump, which corresponds to a water level at the pump. The data from the sensor is stored in a local memory until the collected data can be transmitted to a surface controller (820). Periodically, the stored data will be provided to a transceiver which generates electrical signals which embody the data (830). The transceiver is connected to a toroidal coil which is positioned around a lower end of a rod which drives the pump. The electrical signals generated by the transceiver are applied to the coil, which causes corresponding currents to be induced in the rod (840). These currents are carried through the pump rod and cause electrical potentials corresponding to the current to be induced in a toroidal coil positioned at an upper end of the rod (850). The electrical potentials induced in the coil are processed by a transceiver coupled to the coil, thereby decoding the potentials to extract from the signal the data which was originally transmitted by the downhole transceiver (860). This data is then provided to a pump controller or some other equipment at the surface of the well for processing or display (870).
As noted above, there are losses in the transmission of data from the downhole equipment to the surface, including resistivity losses and leakage losses. These losses vary with the frequency of the data that is transmitted, as well as the medium (e.g., brine) contained in the annular space between the rod and the tubular. Additionally, while the resistivity losses between the two toroidal coils remain substantially constant for a particular frequency, the overall leakage losses may change as a result of the amount and conductivity of the fluid in the annular space. The greater the conductivity of the liquid, the higher the losses will be. Similarly, the greater the length of the occupied by the liquid, the greater the losses will be. Thus, the voltage transfer (Vout/Vin) over the length of the system is dependent upon these factors.
Referring to
It can be seen in the figure that the voltage transfer is greatest when the annular space is filled with air. At very low frequencies, the transfer function is relatively low, but it rises relatively rapidly as the frequency approaches 100 Hz, then begins to level off and remains at a high level as the signal frequency is increased to 100 kHz. When the annular space is filled with tap water, the voltage transfer is slightly lower, but very similar to that of air up to about 100 Hz. The curve stays near its maximum from about 100 Hz to 5 kHz, then decreases above 5 kHz. The curves for 5 kppm brine and 10 kppm brine are significantly lower, with their maximum performance falling between about 30 Hz and 300 Hz.
In an actual installation, the distance between the lower toroidal coil and the upper toroidal coil may be hundreds, or even thousands of feet. Usually, only a portion of the overall length of the annular space will be filled with fluid. The portion of the annular space which is occupied by liquid (e.g., brine) and the portion which is occupied by air may vary, so the overall leakage losses may change, but it is not uncommon for the liquid to fill approximately 50 feet of the annular space. Thus, although the signal may drop by approximately half (in the range from 30 Hz to 300 Hz) through the liquid-filled portion of the conduit, the air-filled portion will experience a much smaller drop. The system may therefore be useful in even deep wells, particularly when using signals in the 30 Hz-300 Hz range.
As noted above, the TCL system can be used to transmit power as well as data. For example, power that is generated at the surface of the well may be communicated via the TCL system to equipment installed downhole in the well, which can be consumed immediately, or stored for later use by the downhole equipment. The structure of a power transmission system in accordance with some embodiments is illustrated in
As shown in these figures, a power source 1010 is coupled to an upper toroidal coil 1020. The toroidal coil is positioned around a pump rod 1030 which extends downhole into the well within tubular 1040. A lower toroidal coil 1060 is positioned around the rod at a downhole location near a piece of downhole equipment which requires power from the surface.
In this case, AC power is provided by power source 1010. The AC voltage signals generated by source 1010 are applied to toroidal coil 1020, generating magnetic fields which induce currents in rod 1030. Electrical conductors 1050 and 1055 electrically couple rod 1030 to tubular 1040 in order to form a complete circuit through which current can flow. The current induced in rod 1030 induces a voltage in lower toroidal coil 1060. This voltage is provided to a rectifier 1070 which rectifies the AC power to DC. The DC power is then provided to a battery 1080, charging the battery. When needed, equipment 1090 can draw power from battery 1080, enabling the equipment to operate.
The operation of this TCL power transmission system is illustrated in
Although in this embodiment power is transmitted from a surface power source to a single piece of equipment that is installed downhole in a well, it is possible in alternative embodiments for power to be transmitted in the same manner to several different locations within the well. For example, one or more additional toroidal coils which are coupled to corresponding additional pieces of downhole electric equipment may be positioned at different axial locations, so that the current in the rod or tubular induces voltages in each of these downhole toroidal coils, providing power to each of the corresponding pieces of equipment. In other alternative embodiments, the power source may be located in the well, and may provide power to equipment at other locations within the well. For instance, a downhole electric generator may be installed in the well at a first axial position, and power from this generator may be provided to equipment which is co-located with the generator, as well as being provided via a TCL system as described above to equipment located at a second axial position in the well. Exemplary friction-based downhole power generators are described in more detail below. The operation of the TCL system would be the same as described above for transmission of power from a surface-based source.
Referring to
As shown in
A wireless gauge 1360 is installed downhole in the well near PCP 1330. Wireless gauge 1360 in this embodiment is configured to monitor the pressure of the water in the well and to communicate this information to a controller 1370 at the surface of the well. Surface controller 1370 is coupled to drive 1340 and prime mover 1345 and is configured to cause these units to drive rod 1350 and PCP 1330 as needed to remove water from the well. When the water level in the well is low enough to allow gas to be produced, surface controller 1370 controls driver 1340 and prime mover 1345 to stop, suspending operation of PCP 1330 so that pump off conditions do not cause overheating of PCP 1330.
Referring to
A wireless gauge system 1440 is positioned near pump system 1420. Wireless gauge system 1440 includes a gauge subsystem 1442 and a transmitter subsystem 1444. Gauge subsystem 1442 may include pressure and temperature sensors, as well as any other types of sensors that might be desirable. Gauge subsystem 1442 receives power from a power subsystem 1446 which is coupled to rod 1430. Power subsystem 1446 is also coupled to transmitter subsystem 1444. Transmitter subsystem 1444 receives data from gauge subsystem 1442 and wirelessly transmits this data (using power from power subsystem 1446) to a receiver 1452 of surface control system 1450. The received data can then be used by a drive controller 1454 of the surface control system 1450 to control the operation of drive 1410.
Because gauge system 1440 is wireless, it must provide its own power to gauge subsystem 1442 and transmitter subsystem 1444. This power is provided by a power subsystem 1446, which includes components for generation of power from frictional heating and components for storage of the generated power. As will be described in more detail below, the power generation components include a thermoelectric generator which uses temperature differentials to produce an electrical potential. This potential is used to charge a battery, capacitor or other energy storage device. The energy stored in this device is then used as needed to power gauge subsystem 1442 and transmitter subsystem 1444.
Referring to
An example of a typical TEG is depicted in
The TEG of
In the systems disclosed herein, the hot side of TEG 1510 is exposed to heat that is generated by friction with the rod coupling the surface drive to the pump system. This frictional heating is provided in some embodiments by placing a “friction body” in thermal contact with both the rod and the hot side of TEG 1510. As the friction body moves against the surface of the rod (which may be referred to herein as a “friction surface”), frictional heating is generated, and this heat energy is conducted through the friction body to the hot side of TEG 1510. A “friction body” may be any structure coupled to the TEG that is used to generate frictional heating. The friction body is not strictly necessary, but may be used, for example, to reduce wear and mechanical stress on the TEG itself.
In some embodiments, the TEG and the friction body may remain in substantially static positions while the rod moves (either rotating or linearly reciprocating), so that there is friction between the friction body and the friction surface on the rod. In other embodiments, the TEG and the friction body may be mounted on the rod so that they move with the rod. In this case, the friction body will move with respect to a stationary component that is positioned adjacent to the rod and provides a friction surface, so that frictional heat is generated between the friction body and this stationary friction surface when the rod and the friction body move.
The friction body may have any suitable configuration. The friction body may, for example, comprise a simple pad positioned between and in direct contact with the TEG and the rod. In some embodiments, the friction body may have a more complex configuration (e.g., it may be in thermal contact with a heat pipe, and the heat pipe may be coupled to transfer heat energy to the hot side of the TEG).
In some embodiments, the cold side of the TEG is positioned so that it is exposed to the space between the production tubing and the rod that drives the pump system. The cold side of the TEG is cooled by fluids flowing through this space. Heat pipes may be used to transfer heat from the cool side of the TEG to locations within the production tubing that are cooler than the location of the TEG itself. In other embodiments, the cold side of the TEG may be positioned so that it is exposed to the annular space between the production tubing and the well casing (or wellbore). The gas which is produced from a typical coal seam gas well flows through this annular space from the producing region of the well to the surface. The flowing gas serves as a cooling medium for the cold side of the TEG. The device may be configured to expose the cold side of the TEG directly to this cooling flow of gas, or means such as heat pipes may be used to transfer heat energy from the cold side of the TEG to the gas.
Referring to
In this embodiment, TEG 1710 is potted with the cold side of the TEG exposed to the annular space 1750 between rod 1730 and production tubing 1760. The cold side of the TEG is therefore submersed in the fluid in this annular space. As fluid flows through this space (as indicated by the arrows in the figure), the fluid absorbs heat from the cold side of TEG 1710, maintaining a temperature differential between the cold side and the hot side of the device. Electrical conductors 1770 extend from TEG 1710 to electrical circuitry and/or an energy storage device (e.g. capacitor or battery), where the generated electrical energy is stored. The stored electrical energy is then used by the gauge and wireless transmitter subsystems.
It should be noted that, although
Referring to
Referring to
Referring to
A pair of TEGs 1940 are mounted on the opposite (radially outward-facing) surface of the spring. As the pump rod moves against the first phase of the spring, the friction-generated heat is transferred through the spring to the hot side of the each of the TEG's. Since the TEG's are positioned very near the point at which the leaf spring contacts the pump rod, no heat pipe is used in this embodiment. The opposite, cold side of each TEG is exposed to the fluid flowing through the annular space between the pump rod and the gauge sub housing. The fluid cools this side of the TEG's and maintains the temperature differential between the hot and cold sides of the devices. Leads from the TEG's extend through a seal 1950 in the gauge sub housing and are connected to power electronics 1960, wireless transceiver 1965 and batteries 1970 that are mounted in the housing.
Referring to
Referring to
Bellows 1980, in addition to providing contact between the friction body and pump rod and centralizing the pump rod, also serves to provide environmental isolation of the TEG device and associated electrical contacts and components from fluids (e.g., water) flowing through the annular space between the pump rod and the gauge sub housing. The bellows may therefore prevent corrosion and fouling that might otherwise result from exposure to these fluids. The bellows may also prevent some heat loss from the thermally conductive material of the friction body to the surrounding fluids.
The examples above show the TEG devices incorporated into stationary assemblies. The frictional heating is generated by contact between friction bodies in these stationary assemblies and the moving pump rod. As indicated above, the TEG devices and friction bodies may alternatively be incorporated into the pump rod itself (i.e., they. May be stationary with respect to the pump rod, rather than the pump stator). In these alternative embodiments, a stationary component such as a collar that encircles the pump rod may be provided, where the friction body rubs against the stationary component as the pump rod rotates or reciprocates, thereby generating heat that is converted to electricity by the TEG in the pump rod.
As noted above, the power generated by the TEG devices is stored (e.g., in batteries, capacitors or other energy storage devices) and the stored energy is then used to operate the gauge and wireless communication subsystems. The gauge subsystem may include pressure sensors, temperature sensors, or any other type of sensor that may be desired. (In some embodiments, the disclosed power generation subsystem may be used to drive tools other than gauges or communication systems.) The information that is provided by the gauge subsystem may be processed as needed and provided to a wireless communication subsystem (e.g., transmitter, receiver or transceiver) so that it may be communicated to the surface control system, which may then use the information to control the drive for the pump system. The wireless communication system may use any appropriate means (e.g., acoustic, electrical, magnetic, etc.) to communicate data to the surface control system. Several exemplary and non-limiting examples of suitable communication mechanisms are described below.
As used herein, a term preceded by “a” or “an” (and “the” when antecedent basis is “a” or “an”) includes both singular and plural of such term unless the context clearly dictates otherwise. Also, as used in the description herein, the meaning of “in” includes “in” and “on” unless the context clearly dictates otherwise.
Additionally, any examples or illustrations given herein are not to be regarded in any way as restrictions on, limits to, or express definitions of, any term or terms with which they are utilized. Instead, these examples or illustrations are to be regarded as being described with respect to one particular embodiment and as illustrative only. Those of ordinary skill in the art will appreciate that any term or terms with which these examples or illustrations are utilized will encompass other embodiments which may or may not be given therewith or elsewhere in the specification and all such embodiments are intended to be included within the scope of that term or terms. Language designating such nonlimiting examples and illustrations includes, but is not limited to: “for example,” “for instance,” “e.g.,” “in one embodiment.”
Reference throughout this specification to “one embodiment,” “an embodiment,” or “a specific embodiment” or similar terminology means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment and may not necessarily be present in all embodiments. Thus, respective appearances of the phrases “in one embodiment,” “in an embodiment,” or “in a specific embodiment” or similar terminology in various places throughout this specification are not necessarily referring to the same embodiment. Furthermore, the particular features, structures, or characteristics of any particular embodiment may be combined in any suitable manner with one or more other embodiments. It is to be understood that other variations and modifications of the embodiments described and illustrated herein are possible in light of the teachings herein and are to be considered as part of the spirit and scope of the invention.
Although the steps, operations, or computations may be presented in a specific order, this order may be changed in different embodiments. In some embodiments, to the extent multiple steps are shown as sequential in this specification, some combination of such steps in alternative embodiments may be performed at the same time. The sequence of operations described herein can be interrupted, suspended, or otherwise controlled by another process.
It will also be appreciated that one or more of the elements depicted in the drawings/figures can also be implemented in a more separated or integrated manner, or even removed or rendered as inoperable in certain cases, as is useful in accordance with a particular application. Additionally, any signal arrows in the drawings/figures should be considered only as exemplary, and not limiting, unless otherwise specifically noted.
Use of the embodiments disclosed herein may provide a number of advantages over prior art systems that have wired communication systems. For example, disclosed embodiments are suitable for measuring the hydrostatic head in coal seam gas wells on a continuous basis, allowing timely decisions on PCP on/off operation sequences depending on water and gas production rates from the formation. These embodiments avoid problems relating to entanglement of wired gauges during deployment of PCP strings into wells and the extraction of PCP strings from wells. These embodiments also avoid problems relating to gauge failure due to damaged cables or loss of electrical connectivity. Embodiments further avoid the need to kill wells and suffer possible production losses. Embodiments may avoid the cost of spooling units and may reduce installation crews (from 2 people to 1 person).
Benefits, other advantages, and solutions to problems have been described above with regard to specific embodiments. However, the benefits, advantages, solutions to problems, and any component(s) that may cause any benefit, advantage, or solution to occur or become more pronounced are not to be construed as a critical, required, or essential feature or component.
This application claims priority under 35 U.S.C. § 119(e) to U.S. Provisional Application No. 62/848,364, entitled “Systems and Methods for Wireless Communication in a Well”, filed May 15, 2019, which is fully incorporated herein by reference for all purposes.
| Number | Name | Date | Kind |
|---|---|---|---|
| 4057781 | Scherbatskoy | Nov 1977 | A |
| 4302757 | Still | Nov 1981 | A |
| 20090166023 | Svenning | Jul 2009 | A1 |
| 20170356274 | Thompson | Dec 2017 | A1 |
| 20190292905 | Ross | Sep 2019 | A1 |
| Number | Date | Country | |
|---|---|---|---|
| 20200362691 A1 | Nov 2020 | US |
| Number | Date | Country | |
|---|---|---|---|
| 62848364 | May 2019 | US |
