METHOD AND APPARATUS FOR MONITORING A DOWNHOLE TOOL

Abstract

A telemetry system and method configured to communicate a wellbore parameter such as fluid composition, temperature, and pressure. In one embodiment, a plurality of tracers is stored downhole, and each of the tracers represents a different value of the wellbore parameter. After measuring the wellbore parameter, the measured value is correlated to one or more of the plurality of tracers that is equivalent to the measured value of the downhole parameter. The one or more tracers representing the measured value are then released from their respective containers to travel upstream. A sensor located upstream may detect the one or more tracers, which are then correlated back to obtain the measured value of the wellbore parameter. In another embodiment, ratiometric amounts of the tracers may be used to represent additional values of the wellbore parameter.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. Provisional Patent Application No. 61/624,850, filed Apr. 16, 2012; U.S. Provisional Patent Application No. 61/650,421, filed May 22, 2012; U.S. Provisional Patent Application No. 61/798,767, filed Mar. 15, 2013; and U.S. Provisional Patent Application No. 61/800,614, filed Mar. 15, 2013; which applications are incorporated herein by reference in their entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to a telemetry system for communicating information from a downhole tool. Particularly, embodiments of the invention relate to a chemical telemetry system for communicating information from a downhole tool.

2. Description of the Related Art

Optimal oil production from the reservoir depends upon reliable knowledge of the reservoir characteristics. Traditional methods for reservoir monitoring include seismic log interpretation, well pressure testing, production fluid analysis, and production history matching. Due to the complexity of the reservoir, all information available is valuable in order to give the operator the best possible knowledge about the dynamics in the reservoir.

Fiber or electrical cables with a sensor have been used in the industry to communicate information to and from a downhole tool. However, one drawback of cable is that it requires a direct connection with the downhole tool. This direct connection increases the cost of the operation.

There is a need, therefore, for a telemetry system to communicate information about the wellbore from a downhole tool.

SUMMARY OF THE INVENTION

In one embodiment, a method of communicating a wellbore parameter from a downhole tool includes providing a plurality of tracers for representing a value of the wellbore parameter; measuring the wellbore parameter using a sensor; correlating the wellbore parameter to a value represented by one or more of the plurality of tracers; releasing the one or more of the plurality of tracers to travel upstream; detecting presence of the one or more of the plurality of tracers; and determining the wellbore parameter from the detected one or more of the plurality of tracers.

In another embodiment, a system for communicating a wellbore parameter from a downhole tool includes a plurality of tracers for representing a value of the wellbore parameter; a plurality of containers for storing the plurality of tracers; a first sensor for measuring the wellbore parameter; a downhole controller configured to correlate the wellbore parameter to one or more of the plurality of tracers and configured to release the one or more of the plurality of the tracers; an second sensor for detecting presence of the one or more of the plurality of tracers; and an uphole controller configured to determine the wellbore parameter from the detected one or more of the plurality of tracers.

In one or more of the embodiment disclosed herein, each of the plurality of tracers represents a different value of the wellbore parameter.

In one or more of the embodiment disclosed herein, each of the plurality of tracers comprises a chemical.

In another embodiment, a method of communicating a wellbore parameter from a downhole tool includes providing a plurality of tracers for representing a value of the wellbore parameter; measuring the wellbore parameter using a sensor; correlating the wellbore parameter to a value represented by a ratiometric amount of one or more of the plurality of tracers; releasing the ratiometric amount of one or more of the plurality of tracers to travel upstream; detecting presence of the ratiometric amount of one or more of the plurality of tracers; and determining the wellbore parameter from the detected ratiometric amount of one or more of the plurality of tracers.

In one or more of the embodiment disclosed herein, the method further includes releasing a calibration dosage of the plurality of tracers.

In another embodiment, a method of monitoring status of a downhole tool includes providing a plurality of tracers for representing a status of the downhole tool; changing the status of the downhole tool; and releasing a tracer representing the changed status of the downhole tool. In another embodiment, changing the status of the downhole tool comprises moving a component of the downhole tool. In yet another embodiment, the tracer is released in response to movement of the component.

In another embodiment, a method of monitoring a downhole tool includes storing the plurality of tracers in a plurality of chambers, wherein the tracers in each of the plurality of chambers represent a different position of a component of the downhole tool; moving the component to change the position of the component; sequentially opening the plurality of chambers as the component is being moved, thereby releasing the tracers from the opened chambers; detecting the tracers being released; and determining the position of the component. In another embodiment, the plurality of chambers are closed by the component. In yet another embodiment, the plurality of chambers are closed by a respective cover that is coupled to the component.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, 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 invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 shows an exemplary embodiment of a telemetry system.

FIG. 2 is a table showing the exemplary values of the tracers B1, B2, B3 in the first zone of the telemetry system of FIG. 1.

FIG. 3 shows an exemplary embodiment of a telemetry system for use with a multilateral wellbore.

FIG. 4 shows an exemplary embodiment of a telemetry system for use in a fracturing operation. FIG. 4A illustrates an exemplary embodiment of a container.

FIG. 5 shows an exemplary embodiment of a telemetry system for use with a subsurface valve.

FIG. 6 shows an exemplary embodiment of a telemetry system for use with a downhole pump.

FIG. 7 shows an exemplary embodiment of a telemetry system for use with a steam assisted gravity drainage system.

FIGS. 8A-B illustrate another embodiment of a chemical communication system for monitoring a downhole tool.

FIG. 9 illustrates a partial view of another embodiment of a valve.

FIG. 10 is an exemplary graph showing measured values of tracers released in ratiometric amounts.

FIG. 11 is an exemplary graph showing measured values of one tracer released as a function of time.

FIG. 12 is an exemplary graph showing measured values of one tracer released as a function of time and concentration.

DETAILED DESCRIPTION

Embodiments of the present invention relate to a telemetry system and method for communicating a wellbore parameter such as fluid composition, temperature, and pressure. In one embodiment, a plurality of tracers is stored downhole, and each of the tracers represents a different value of the wellbore parameter. After measuring the wellbore parameter, the measured value is correlated to one or more of the plurality of tracers that is equivalent to the measured value of the downhole parameter. The one or more tracers representing the measured value are then released from their respective containers to travel upstream. A sensor located upstream may detect the one or more tracers, which are then correlated back to obtain the measured value of the wellbore parameter.

In one embodiment, a code may be used to convey information about a wellbore parameter, such as fluid composition, temperature, and pressure. The code may include a plurality of code elements. Each of the code elements may represent a different value of the wellbore parameter. The value represented may be a single value or a range of values. The code may be presented by a plurality of tracers, where each of the code elements is represented by a tracer or a combination of different tracers. In one embodiment, each of the plurality of tracers is initially stored in its respective container.

In operation, after obtaining a measured value of the wellbore parameter, the measured value is then ascribed to a code element CE1 in the code. The tracer or combination of tracers representing the code element is then released from its container. For example, if the plurality of tracers include Z1, Z2, and Z3, and the code element is represented by tracer Z1; then tracer Z1 will be released from its container and allowed to travel uphole. A sensor located uphole may detect the presence of tracer Z1 and determine the specific value or range of values of the wellbore parameter as a result of detecting the tracer Z1. In another example, the measured value may be ascribed to a different code element CE2 which may be represented by a combination of Z2 and Z3. In this instance, both tracer Z2 and tracer Z3 will be released from their respective container. When the uphole sensor detects the presence of both tracers, it may determine the specific value or range of values of the wellbore parameter. In another embodiment, the combination of tracers may be released simultaneously or sequentially. For example, tracers Z2 and Z3 may be released at the same time or sequentially.

In this respect, the number of tracers required to represent a set of code elements will be less than the number of code elements in the code. In the current example, three tracers may be used to represent a set of seven different code elements. In another example, two tracers may be used to represent a set of three code elements. Another advantage of this system is that the measured value is not communicated using the concentration of the tracer released into the wellbore. Instead, the measured value is communicated by the tracer or combination of different tracers released. As a result, in some embodiments, only the smallest amount of tracer needed for detection is required to be released. This advantage allows the container to be configured for a known number of releases. It is contemplated that communication using the code may be applicable in each of the embodiments described herein.

In one embodiment, the plurality of tracers may be used to convey information about a wellbore parameter, such as fluid composition, temperature, and pressure. Each of the tracers Z1, Z2, Z3 may represent a different value of the wellbore parameter. The value may be a specific value or a range. The plurality of tracers may be used in combination to represent a value that is outside of the value of an individual tracer. In one embodiment, each of the plurality of tracers is initially stored in its respective container. In operation, after obtaining a measured value of the wellbore parameter, the measured value is then correlated to an equivalent value represented by one or more of the tracers. For example, if the value represented by tracer Z1 is equivalent to the measured value; then tracer Z1 will be released from its container and allowed to travel uphole. A sensor located uphole may detect the presence of tracer Z1 and determine that the value of the wellbore parameter is within the value represented by tracer Z1. In another example, the measured value may be represented by a combination of the tracers. In this instance, the measured value may be represented by the total value represented by tracer Z2 and tracer Z3. In this respect, both tracer Z2 and tracer Z3 will be released from their respective container. When the uphole sensor detects the presence of both tracers, it will determine that the measured value is within a range represented by the combined value of tracers Z1 and Z2. In this respect, the number of tracers required to represent a set of values will be less than the number of values in the set. In the current example, three tracers may be used to represent a set of seven different values. In another example, two tracers may be used to represent a set of three different values. Another advantage of this system is that the measured value is not correlated to the concentration of the tracer released into the wellbore. Instead, the measured value is correlated to the tracer or combination of different tracers released. As a result, in some embodiment, only the smallest amount needed for detection is required to be released. This advantage allows the container to be configured for a known number of releases.

In one embodiment, the tracers may be chemicals that can travel in the wellbore without being consumed, and therefore, detected at another location. In another embodiment, the tracers may be chemicals not naturally found in the wellbore. Suitable chemicals may include radioactive or non-radioactive isotopes. Suitable non-radioactive tracers include salts of naphthalenesulfonic acids, salts of amino naphthalenesulfonic acids, fluorescein and fluorinated benzoic acids. ³H-labelled or ¹⁴C-labelled tracers of the same kind of components may also be applied. Radioactive tracers such as beta emitters may also be used. Exemplary tracers include chemicals that can be detected using spectroscopic or electromagnetic means, such as radiometric, magnetic, or optical devices. Additionally, particle size detection using tracers such as silicon or other nanoparticles is also contemplated. Other exemplary chemicals include fluorobenzoates, chlorobenzoates, fluoromethylbenzoates, perfluoroaliphatic acids, etc. Depending upon the natural chemistry of the wellbore and the types of chemicals being introduced for stimulation, remediation, fracturing, etc. the selection of chemicals for the tracer may be different.

FIG. 1 shows an exemplary embodiment of a telemetry system 100. The telemetry system 100 is provided in a wellbore 20 for producing hydrocarbon. The wellbore 20 includes a plurality of packers 21, 22, 23 positioned to isolate a plurality of production zones 31, 32. The telemetry system 100 includes a first downhole sensor 41 configured to measure a wellbore parameter associate with the first zone 31. For example, the first downhole sensor 41 may be configured to measure the amount of water in the fluid produced at the first zone 31, which may also be referred to as “water cut.” A plurality of containers 51, 52, 53 may be used to store tracers B1, B2, B3, respectively. In one embodiment, the containers 51, 52, 53 may be pressurized and may be operated by a downhole controller 61. The controller 61 is also connected to the first downhole sensor 41 and may receive signals from the sensor 41 regarding the measured value of the wellbore parameter. The controller 61 is configured to correlate the measured value to the tracers B1, B2, B3, or combination of tracers that represent the measured value. The system 100 also includes a detection system 80 configured to detect the released tracers B1, B2, B3, and configured to determine the measured value or range of the wellbore parameter based on the detected tracers B1, B2, B3. In one embodiment, the detection system 80 may include a tracer sensor for detecting the tracers and a controller for correlating the detected tracers to the value of the wellbore parameter. In another embodiment, the tracer sensor may be a single tracer sensor adapted to detect each of the sensors or a plurality of sensors which are each adapted to detect a different tracer. In another embodiment, the measured values may be ascribed to a code element in a code, and each code element is assigned to a tracer of combination of tracers.

FIG. 2 is a table showing the exemplary values of the tracers B1, B2, B3 in the containers 51, 52, 53 of the telemetry system 100. In the example, the tracers represent a water cut range. As shown, the tracers B1, B2, B3 represent water cut ranges 1, 2, and 4, respectively. Each of the values of ranges 3, 5, and 6 are represented by a combined release of two of the tracers. The value of range 7 is represented by a combined release of all three tracers. Thus, if all three tracers are detected, it can be determined that the water cut range is between 0.875 and 1.0. It must be noted that values in the FIG. 2 are only examples. The tracers may be assigned to any suitable range of values to communicate the measured downhole parameter. For example, the tracers B1, B2, B3 may be used to represent a total water cut range between 0.25 to 0.75. In addition, although FIG. 2 shows the tracers have equal units of values (i.e., 0.125), it is contemplated that the tracers may be assigned to values that are not equal units; for example, B2 may represent a range of 0.25 instead of 0.125.

Referring back to FIG. 1, the system 100 may optionally include another set of tracers C1, C2, C3 for communicating information about the second production zone 32, such as the water cut in the zone 32. The tracers C1, C2, C3 may be separately stored in containers 61, 62, 63. The tracers C1, C2, C3 for the second zone 32 should be different from the tracers B1, B2, B3 of the first zone 31 to help identify the zone from which the tracers are sent. A second sensor 42 is used to measure the wellbore parameter of the second zone 2. The second sensor 42 and the containers 61, 62, 63 may be controlled by the controller 61 or a second controller.

In one embodiment, the controller 61 may be configured to send information about the water cut or other wellbore parameter at predetermined time periods. For example, the controller 61 may be configured to release the tracers daily, weekly, monthly, quarterly, or any suitable time frame. The controller 61 may be configured to release an amount of tracer that is sufficient for detection by the detection system 80. Because only a low amount of power is required to read the sensors, open and close the container, and operate the internal clock, the battery life of the system is increased. Thus, the telemetry system 100 may be a low power system that has a long life, or large number of iterations, or both.

In operation, the telemetry system 100 may be used to communicate a wellbore parameter such as the water cut of the wellbore fluid. In one embodiment, the controller 61 may be configured to communicate the water cut on a daily basis. To that end, the controller 61 may obtain the value of the water cut from the first sensor 41. The controller 61 may then correlate the measured value to the tracers that represent the measured value. In one example, if the measured value is 0.35, then the controller 61 may determine that the measured value is within the range represented by tracer B2 and then release tracer B2 from its container 52. The tracer B2 travels uphole to the surface and is detected by the detection system 80. The detection of tracer B2 communicates to the detection system 80 that the water cut in the first zone is between 0.25 and 0.375. One day later, the controller 61 may receive another measured value of the water cut from the first sensor 41. In another example, if the measured value of the water cut has increased to 0.4, then the controller 61 may correlate that to a value represented by a combination of tracers B1 and B2. As a result, the controller 61 will release tracers B1 and B2 from their respective containers 51, 52. The detection of tracers B1 and B2 communicates to the detection system 80 that the water cut in the first zone is between 0.375 and 0.5. In one embodiment, the tracers B1 and B2 may be released in a unique pattern. For example, tracer B1 and tracer B2 may be released sequentially or simultaneously. In another embodiment, the controller 61 may also communicate the water cut of the second zone 32 by obtaining the measured value from the second sensor 42 and releasing the equivalent tracers C1, C2, C3 of the second zone 32. The tracers selected for the second zone 32 are different from the tracers of the first zone 31 to help distinguish the zones 31, 32. The tracers of the second zone 32 may also be released on a daily basis. In one embodiment, the tracers of the second zone 32 are released at a different time during the day than the first zone 31. For example, the tracers of the second zone 32 may be released 12 hours after the first zone 31. The tracers C1, C2, C3 may be assigned the same water cut values as the tracers B1, B2, B3 from the first zone. The detection system 80 may be configured to detect the tracers C1, C2, C3 and determine the water cut value from the tracers. In another embodiment, the telemetry system 100 may include one or more groups of sensors and tracers for measuring other wellbore parameters such as temperature and pressure. In one example, tracers for conveying temperature may be released on a weekly basis, while tracers for conveying pressure may be released on a daily basis.

Although FIG. 1 shows a single wellbore system, in another embodiment, the telemetry system may be used in a multilateral wellbore system. The laterals may include one or more tracers and sensors to communicate information regarding operation or production of various zones of the laterals. As shown in FIG. 3, each lateral 110, 120, 130 may include two sets of sensors and tracers at each inflow control device. The first lateral 110 may include two inflow control devices 111, 112 for two different production zones. An exemplary inflow control device may be a sliding sleeve valve. Each inflow control device 111, 112 may be equipped with a sensor to measure a wellbore parameter and a set of tracers for communicating the measured values in a similar manner as shown in FIG. 1. For example, the first inflow control device 111 may be associated with a downhole sensor 41 and tracers B1, B2, B3, and the second inflow control device 112 may be associated with downhole sensor 42 and tracers C1, C2, C3. Each of the sensors 41, 42 may be adapted to measure a wellbore parameter such as flow rate, fluid composition, temperature, and pressure. In one embodiment, each of the inflow control devices may be provided with additional sensors to measure additional parameters. For example, one or more of the inflow control devices may be equipped a first sensor for measuring fluid composition and a second sensor for measuring temperature. The second lateral 120 may also include two inflow control devices 121, 122, each with its own sensor and set of tracers. Similarly, the third lateral 130 may include two inflow control devices 131, 132, each with its own sensor and set of tracers. The uniqueness of each tracer assists with identification of the particular inflow control device associated with the tracer. In this respect, the tracer may communicate information to surface regarding the particular inflow control device. For example, the tracers B1, B2, B3 may communicate the flow rate of the fluid flowing through the first inflow control device 111 in the first lateral 110. In addition to communicating the measured flow rate, the tracers B1, B2, B3 also indicate that the inflow control device 111 is in operation. In another example, a failure to detect tracers from inflow control device 132 may indicated that the inflow control device 132 is closed or is experiencing a problem. It must be noted that each lateral may include more than two inflow control devices, such as five, ten, fifteen, or any suitable number of inflow control devices. In another embodiment, the measured values may be ascribed to a code element in a code, and each code element is assigned to a tracer of combination of tracers.

In another embodiment, the telemetry system may be used in a fracturing operation. FIG. 4 illustrates a wellbore 140 having multiple fracture sleeves 141, 142, 143 that are sequentially opened to allow fracturing fluid to flow out of the wellbore and fracture the formation. The fracture sleeves 141, 142, 143 are associated with a set of tracers to communicate whether the respective fracture sleeve was opened during the fracturing operation. In some operations, the fracture fluid is continuously injected into the wellbore during the fracture operation. In such operations, the release of chemical tracers is delayed until the fluid flow direction is up the wellbore. In one exemplary embodiment, each of the tracers associated with the second fracture sleeve 142 may be stored in a container 150 having a gate valve 152 and a check valve 154, as shown in FIG. 4A. The gate valve 152 opens in response to opening of the fracture sleeve 142. The check valve 154 opens when the annulus pressure is greater than the wellbore pressure. An exemplary check valve is a one way valve such as a flapper valve or a poppet valve.

In operation, when the fracture sleeve 142 opens, the controller opens the gate valve 152 in response. However, the tracer is not released until the check valve 154 is opened. While the fracturing fluid is being injected, the check valve 154 remains closed because the wellbore pressure generated by the fracturing fluid is greater than the annulus pressure. When the injection ceases and the wellbore pressure drops below annulus pressure, the check valve 154 opens to release the tracer from the container 150. The tracer is released into the wellbore and is carried up to the surface. Detection of the tracer at the surface indicates that the fracture sleeve 142 opened during the operation. However, if no tracers for a particular fracture sleeve are detected, then it is an indication that the particular fracture sleeve may have failed to open. In another embodiment, the measured values may be ascribed to a code element in a code, and each code element is assigned to a tracer of combination of tracers.

In another embodiment, the tracers may be used to indicate the open status of a sliding sleeve or other valve devices. For example, a valve may be controlled from surface between open, close, or partially open positions. However, it is generally difficult to determine the extent to which the valve is partially open. In one embodiment, the valve may include a sensor configured to measure the extent of opening of the valve. A plurality of containers may be used to store tracers E1, E2, E3, respectively, to communicate the status of the valve. In one embodiment, the containers may be pressurized and may be operated by a downhole controller. The controller is also connected to the sensor and may receive signals from the sensor regarding the extent of valve opening. The controller is configured to correlate the measured value to the tracers E1, E2, E3, or combination of tracers that represent the measured value. In one example, the tracers E1, E2, E3 may be used to represent ranges 1-7 as shown in FIG. 1. The system also includes a detection system configured to detect the released tracers E1, E2, E3, and configured to determine the status of the valve based on the detected tracers E1, E2, E3.

In operation, a signal may be sent to the valve to at least partially open the valve, for example, 60% open. The sensor measures the amount of opening of the valve and communicates the data to the controller. In turn, the controller releases one or more tracers to communicate to the surface the extent of the valve opening. For example, the controller may determine that the measured value of 60% open is within the range represented by tracer E3 and thus, release tracer E3 from its container. The tracer E3 travels up the wellbore and is detected by the detection system. The detection of tracer E3 communicates to the detection system that the valve is 50% to 62.5% open. Later, the controller may receive another measured value of the valve, for example, 70% open. Then, the controller may correlate the measured value to a value represented by a combination of tracers E1 and E3. As a result, the controller releases tracers E1 and E3 from their respective containers. The detection of tracers E1 and E3 indicates that the valve is opened in a range between 62.5% and 75%. In this manner, the tracers may be used as an encoding to communicate the status of the valve. It must be noted that the range designations of the tracers may be different from the ranges in FIG. 1. It also must be noted that additional tracers may be used to further define the possible ranges represented by the tracers. In another embodiment, the measured values may be ascribed to a code element in a code, and each code element is assigned to a tracer of combination of tracers.

In another embodiment, the release of the tracers may be coupled directly to the opening of the sleeve of the downhole valve. In one example, the tracers may be stored in sequential chambers of a container or containers that are closed by the sleeve. Each chamber may store a different tracer or combination of tracers, which represents the open status of the sleeve. As the sleeve moves to open the downhole valve, it will sequentially uncover one or more of the chambers. The tracers in the chambers opened by the sleeve will be released into the flow stream, such as the tubing, the annulus between the tubing and casing, a hydraulic line, and combinations thereof. When detected, the tracers will be analyzed at surface to determine the valve position. In another embodiment, the sleeve may be coupled to a cover of the chambers. As the sleeve moves, it will also move the cover to open the respective chambers to release the tracers. Although the description relates to a downhole valve, it is contemplated that the system may be used to indicate the position status of any suitable downhole tool. In another embodiment, the chemical communication system may be used to communicate the position of a component of a downhole tool.

In one exemplary operation, five chambers may be used to represent the position of the sleeve in twenty percent increments. FIG. 8A is a partial view of the interior of an exemplary embodiment of a downhole valve 400. The valve 400 includes a tubular body 410 and a sliding sleeve 420 disposed adjacent the tubular body 410. The sleeve 420 may include an extension cover 425 that seals off the five chambers 431-435, which are shown as a hidden view with dash lines. Initially, a signal is sent to at least partially open the valve 400, for example, 40% open. As the sleeve 400 opens, it will also sequentially uncover the chambers 431, 432. After reaching the 40% open position, the first two chambers 431, 432 will have been opened. The tracers representing 20% and 40% open positions will be released. The detection system at the surface detects the presence of the tracer or combination of tracers representing 40% open and confirms the sleeve 400 is at least 40% open. If a second signal is later sent to open the valve 400 further, for example to 60%, then the sleeve 420 will uncover the next chamber 433, and the tracers representing 60% open status will be released. When the detection system detects the presence of these tracers, the proper open position of the valve 400 is confirmed. FIG. 8B shows the sliding sleeve 420 has moved up to expose slots 428 in the valve 400 for fluid communication. Also, the first three chambers 431-433 have been opened as a result of the extension cover 425 also moving up. The fourth and fifth chambers 434, 435 are still blocked by the extension cover, as shown by the dash lines.

In another embodiment, the release of the tracers may be controlled by a command such as receiving the command from the surface or from a controller. For example, after opening the sleeve opens three of the chambers 431-433, the release of the tracers may be delayed until a command is received. In one example, a controller may instruct all of the chambers 431-435 to release their tracers. However, only the tracers in chambers 431-433 will release into the flow stream because those chambers have been opened. The tracers in chambers 434-435 cannot release into the flow stream because those chambers are still blocked by the sleeve 400.

FIG. 9 illustrates a partial view of another embodiment of a valve 450. As shown, the extension cover 465 of a sliding sleeve 460 is configured to block off four of the seven chambers 451-457. Particularly, the extensive cover 465 is blocking off chambers 453-455, while chamber 451, 452, 456, and 457 are open to allow release of the tracers. In this respect, the valve 450 is partially open as demonstrated by the chambers 451 and 452 being open. Upon receiving a command to release the tracers, all of the chambers will release their tracers. However, only the tracers from chambers 451, 452, 456, 457 are open to allow the tracers to flow into the flow stream such as inside a tubing. The absence of the tracers from chambers 453-455 at surface will indicate that those chambers are closed and therefore, the position of the sleeve can be determined. If a command to partially close the sleeve 460 is received, then the sleeve 460 will move to close off the second chamber 452, while leaving chambers 451, and 455-457 open. To signal the sleeve 460 has partially closed, another command may be sent to instruct the release of the tracers in the chambers 451-457. As a result, only the tracers in chambers 451 and 455-457 are released and detected at surface, and the tracers from chambers 452-454 would be absent. As a result, partial closure of the sleeve 460 is confirmed.

In another embodiment, the valves may be configured to send a chemical signal even though it is closed. For example, referring back to FIG. 3, if the valve 112 in the first lateral 110 is open and the upstream valve 111 is closed, then fluid entering the downstream valve 112 will flow past the upstream valve 111 on its way to surface. The upstream valve 111 may be preprogrammed to release a tracer to indicate that it is closed. The released tracer may be carried to surface by the fluid entering the downstream valve 112. In another embodiment, the upstream valve 111 may be commanded to release the tracer or released the tracer at preset time intervals.

In another embodiment, the telemetry system may be used to communicate the status of a subsurface safety valve. For example, a subsurface safety valve 200 may include a flapper 210 biased in a normally closed position. During operation, a shift sleeve 215 may be used to open the flapper 210 and lock the flapper 210 in the open position, as shown in FIG. 5. In one embodiment, a tracer may be released from a container 220 to indicate that the flapper 210 has opened. For example, after the shift sleeve 215 has moved axially to open the flapper 210 and lock the flapper 210, the shift sleeve 215 may trigger the release of the tracer. FIG. 5 shows the flapper 210 in the locked, open position. In one embodiment, the shift sleeve 215 may engage a piston 225 to cause the release of the tracer from its container 220. In this manner, the telemetry system may be used to confirm the flapper 210 is in the locked, open position.

In another embodiment, the telemetry system may be used to facilitate control of a downhole pump by communicating wellbore condition adjacent the downhole pump. FIG. 6 shows a wellbore 160 having a progressive cavity pump (“PCP”) for pumping wellbore fluids to surface. In one embodiment, the PCP is an insertable PCP 170 attached to the production tubing 165 in the wellbore. The insertable PCP 170 includes a rotor 171 releasably coupled to the stator 172. In turn, the stator 172 is releasably coupled to the tubing 165 using a latch 167. The insertable PCP may be raised or lowered using a sucker rod 169. In one embodiment, a sensor 180 for measuring the hydrostatic head in the wellbore may be attached to the PCP 170. The PCP 170 may also include the containers 185 for separately storing tracers F1, F2, F3 for communicating the measured value to surface. Each of the tracers may represent a particular value, and two or more of the tracers may be combined to represent different values. The tracers may periodically communicate information about the hydrostatic head in the wellbore. For example, the controller may release the tracers on an hourly, daily, or weekly basis. After the sensor measures the hydrostatic head, then the controller will release the tracer or tracers that represent the measured value. If the hydrostatic head is too high, then the motor speed may be increased to produce more fluid. However, if the hydrostatic head is too low, then the motor speed may be decreased to ensure the fluid column is above the inlet of the PCP 170. In this manner, the PCP 170 may be operated to control the fluid at level close to the inlet of the PCP, thereby increasing efficiency of the pump. In another embodiment, the sensor and tracers may be attached to the rotor and may, optionally, extend below the stator. It is contemplated that additional sensors and tracers may be used to measure and communicate other wellbore parameters such as temperature and composition. In another embodiment, the measured values may be ascribed to a code element in a code, and each code element is assigned to a tracer of combination of tracers.

In another embodiment, the telemetry system may be used to convey information regarding a steam assisted gravity drainage system (“SAGD”). FIG. 7 shows a first wellbore 310 having a first outflow valve 311 and a second outflow valve 312 connected to a first tubular for injecting steam into the formation 305. The steam and other formation fluids may enter a second wellbore 320 and sent to the surface via a first inflow valve 321 and a second inflow valve 322 that are connected via a second tubular. In one embodiment, the steam leaving the first outflow valve 311 may be supplied with a tracer or combination of tracers assigned to the first outflow valve. Similarly, the tracer or combination of tracers assigned to the second outflow valve 312 may be added to the steam leaving the second outflow valve 312. After the steam enters the inflow valves 321, 322 and sent uphole, the detection sensor may identify the tracers in the steam and determine the source of the tracers, i.e., from the first outflow valve 311 or second outflow valve 312. In another embodiment, the inflow valves 321, 322 may be provided with the appropriate sensors and tracers to determine the flow rate, temperature, pressure, and/or composition of the fluids flowing into the second wellbore 320.

In another embodiment, the chemical communication system may be configured to release ratiometric amounts of a tracer to convey information about a wellbore parameter or a downhole tool. For example, each tracer may be released in ratiometric amounts such as a quarter dosage, half dosage, or full dosage. Each ratiometric dosage may represent a different value. In this respect, use of ratiometric dosage effectively increases the range or resolution of values represented by the tracer. It must be noted that the dosages are not limited to a quarter dosage or a half dosage, but can be in any suitable amounts, such as one third, one fifth, or one sixth. In one embodiment, each of the ratiometric dosage may represent equal values. For example, if only one tracer is used, each quarter dosage may represent a value of 0.1 such that the full dosage may represent a value of 0.4. If multiple tracers are used, then ratiometric amounts of one tracer may be combined with ratiometric amounts of one or more other tracers to represent a value. In another embodiment, each partial ratiometric dosage may represent a smaller value within a range of values represented by the full dosage, thereby providing a higher resolution of the measured value. For example, if the full dosage represents a range between 0.2 to 0.3, then each quarter dosage may be 25% of the range.

The system may release a calibration dosage in order to determine the environmental effects on the tracer. The calibration dosage may be used to normalize the data for the ratiometric values. In this instance, the calibration dosage may be referred to as a normalization dosage. In one embodiment, the normalization dosage may be a full dosage of the tracer. The value measured at the surface for the full dosage may be used to determine the ratiometric dosage of the tracer released either after or before the normalization dosage. For example, if the measured value of the ratiometric dosage is about 33% of the measured value of the calibration dosage, then the ratiometric dosage released is a one-third dosage. After determining the ratiometric dosage, the represented value may be obtained. The normalization dosage may be released at any time such as before and/or after releasing the ratiometric dosage. The frequency of release of normalization dosage may be controlled based on time intervals, such as hourly, daily, or weekly. The normalization dosage may also be released based on a particular event, such as prior to measurement, upon receipt of a command sent downhole, or upon measurement of a particular range where a more specific value is desirable. In another embodiment, a unique code represented by the tracers may be released to signal a normalization dosage will be sent.

FIG. 10 is an exemplary graph showing the measured values of three tracers T1, T2, T3 released in ratiometric amounts compared to a normalization dosage of the tracers T1, T2, T3. For each of the tracers, a normalization dosage is released followed by a ratiometric dosage. In this example, the tracers T1, T2, T3 are released in ratiometric amounts of 0.7, 0.4, and 0.5, respectively.

In another embodiment, the tracers may be modulated as a function of time, e.g, width modulation. FIG. 11 is an exemplary graph showing the measured values of one tracer released as a function of time. It must be noted that only one tracer is shown for sake of clarity. It is contemplated that any number of tracers may be modulated as a function of time. In FIG. 11, the tracer is released for a period of about ten minutes as a normalization dosage followed by five minutes as a ratiometric dosage. In another embodiment, the tracers may be modulated using a combination of concentration and time to represent a value. In FIG. 12, the tracer is released at 60% dosage for 5 minutes followed by 40% dosage for 5 minutes. At surface, the detection system can correlate this result to a predetermined value.

In one exemplary embodiment, the system shown in FIG. 1 may be modified such that the tracers B1, B2, B3 may be released in ratiometric amounts such as half dosage and full dosage. In this embodiment, the half dosage may represent 50% of the range of the full dosage, which is equal to 0.0625. Thus, a half dosage may represent the range between 0.25 to 0.3125, and the full dosage may represent the range between 0.3125 to 0.375. In operation, the controller 61 is programmed to release a normalization dosage before measuring the wellbore parameter. The normalization dosage is detected at surface and used to determine any ratiometric dosages. After obtaining the value of the water cut from the first sensor 41, the controller 61 then correlates the measured value to the tracers that represent the measured value. In one example, if the measured value is 0.28, then the controller 61 may determine that the measured value is within the range represented by a half dosage of tracer B2. As a result, a half dosage of tracer B2 is released from its container 52. In one embodiment, the container 52 is opened and tracer released using a mechanically actuated device such as a piston, lever, or a screw. The tracer B2 travels uphole to the surface and is detected by the detection system 80. The detected value of the tracer B2 is then compared to the value of the calibration dosage. The result of the comparison indicates that a half dosage of tracer B2 was released, which communicates to the detection system 80 that the water cut in the first zone is between 0.25 and 0.3125.

In another embodiment, the ratiometric values may be used to further define a range, i.e., to obtain a higher resolution of the measured value. For example, each of the tracers B1, B2, B3 represents a range of 0.125 in to FIG. 2. The half dosage of each tracer and combination of tracers can be used to represent a value in that range. The following example uses the range of B2, which is 0.25 to 0.375, the values of the half dosage of the tracers B1, B2, B3 may be assigned as follows:

• • half B1=0.25-0.275
  • half B2=0.275-0.3
  • half B3=0.3-0.325
  • half B1+half B2=0.325-0.35
  • half B1+half B3=0.35-0.375

In operation, if the water cut value is 0.33, then the controller 61 will release a normal dose of tracer B2 into the wellbore. At surface, the detection system will determine the water cut range is between 0.25 and 0.375, as represented by the detection of a full dosage of tracer B2. Thereafter, the detection system may send a command to the controller 61 to communicate a more specific value. In response, the controller 61 may initially release a calibration dosage of each of the tracers B1, B2, B3 into the wellbore. The value of the calibration dosage measured by the detection system may be used to determine the ratiometric value of the tracers. The controller 61 will then release a half dosage of each of tracer B1 and tracer B2 to represent the more specific value of the water cut. Upon detection by the detection system, the value of the tracers is compared to the value of the calibration dosage. The determination is then made that only half dosage of each of tracers B1, B2 has been released, thereby representing a water cut in the range of 0.325-0.35. In this manner, a more specific value of a wellbore parameter, e.g., water cut, can be obtained using a chemical communication system.

It is contemplated that chemical communication involving ratiometric amounts and/or time based modulation can be used by any suitable downhole tool, including any downhole tool described herein. For example, the position of the sleeve of a downhole valve as described above may be communicated using ratiometric or time based modulation.

In another embodiment, the chemical communication system may be configured to communicate data in portions, which when combined, represents the full data. In one embodiment, the chemical communication system can be used to serially communicate a digit of a value. For example, to communicate a value, one or more tracers may be used to represent numbers 0 to 9. If four tracers are used, they may be assigned the numbers as follows:

• • F1=0
  • F2=1
  • F3=2
  • F4=3
  • F1+F2=4
  • F1+F3=5
  • F1+F4=6
  • F2+F3=7
  • F2+F4=8
  • F3+F4=9

To communicate a pressure of 356 psi, the controller may initially release tracer F4 to represent the number 3 for the first digit in the pressure value. After waiting a period of time sufficient to avoid overlap of tracers between releases, the controller will release tracers F1 and F3 to represent the number 5 for the second digit of the pressure value. Thereafter, the controller will release tracers F1 and F4 to represent the number 6 for the third digit. At surface, the detection system will detect these tracers in the sequence that they are released and determine the digit represented by each tracer or combination of tracers. From the release sequence of the tracers, the detection system will determine the actual value communicated is 356 psi. Optionally, the release of the tracers may be repeated to obtain a second reading to verify the actual value. Another normalization dosage may be optionally released in between the first and second readings to renormalize the tracers' values. In yet another embodiment, the normalization dosage may be sent at the end of the communication to verify the data. In another embodiment, the digits may be communicated in reverse order, such as, units, then tenth, then hundredth, and thousandth.

In another embodiment, each of the digits may be represented by at least two tracers, as follows:

• • G1+G2=0
  • G1+G3=1
  • G1+G4=2
  • G1+G5=3
  • G2+G3=4
  • G2+G4=5
  • G2+G5=6
  • G3+G4=7
  • G3+G5=8
  • G4+G5=9

In another embodiment, the numbers may be represented by ratiometric dosages of the tracer, thereby reducing the number of tracers necessary for communication.

• • G1+0.25 G2=0
  • G1+0.5 G2=1
  • G1+0.75 G2=2
  • G1+G2=3
  • 0.25 G1+0.25 G2=4
  • 0.25 G1+0.5 G2=5
  • 0.25 G1+0.75 G2=6
  • 0.25 G1+G2=7
  • 0.5 G1+0.5 G2=8
  • 0.5 G1+G2=9

Embodiments of the chemical communication system may be used for communication between two downhole devices. In one embodiment, referring back to FIG. 3, the chemical communication system allows the inflow control device 112 to communication with the upstream inflow control device 111 in the first lateral 110 or the inflow control devices in other laterals. For example, when the downstream inflow control device 112 releases the tracers representing the water cut value (or other wellbore parameter) measured by its sensor, the tracers will travel upstream to the detection system at surface. In this embodiment, the upstream inflow control device 111 may be equipped with a detection system for detecting the tracers released by the downstream inflow control device 112 or other devices. If the upstream device 111 determines the released tracers represent a high water cut value, the controller may close the upstream device 111 to prevent inflow of water.

In another embodiment, a command signal such as a coded fluid pressure pulse targeting a specific device may be used to sample one or more devices in a wellbore. Referring again to FIG. 3, a command signal targeting the downstream inflow control device 112 in the first lateral 110 may be sent to trigger the downstream device 112 to convey information about a wellbore parameter or the device 112 by releasing a tracer or combination of tracers. After sampling the downstream device 112, the upstream device 111 can be sampled. A second command signal targeting the upstream inflow control device 111 in the first lateral 110 is sent to trigger the upstream device 111 to convey information about the wellbore parameter or the device 111 by releasing the tracer or combination of tracers. If the tracers in each device 111, 112 are the same, then the command signals may be sent at predetermined time intervals to avoid confusion. The time interval may be minimal or not necessary if the tracers in each device 111, 112 are unique to that device 111, 112. This process may be performed to sample other inflow control devices in the second and third laterals 120, 130.

In yet another embodiment, tracers may be released from the surface to communicate with one or more downhole device. The tracers may be coded to communicate with a particular device or a group of devices. The downhole devices may be equipped with a detection system to detect the tracers released from surface. For example, a tracer or combination tracers targeting inflow control device 111 may be released from the surface. Upon detection of the tracers, the inflow control device 111 may be triggered to communicate a wellbore parameter or data about itself. Because the tracers are coded for the inflow control device 111, the other inflow control devices will ignore the tracers and not respond. In this manner, two-way communication using the tracers may be performed.

In another embodiment, the chemical communication system may be used to communicate information about a downhole device. For example, the tracers may be used to communicate the condition of a battery in the downhole device. In one example, the tracers or combination of tracers may be used to represent the percentage of battery life remaining.

• • G1=20%<life<30%
  • G2=10%<life<20%
  • G1+G2=life<10%
    Thus, the controller may release tracer G2 to communicate the battery life remaining is less than 20%. In another embodiment, ratiometric amounts of the tracers or combination of tracers may be used to communicate the life of the battery. In another embodiment, for multiple devices, each of the devices may be equipped with its unique set of tracers.

In another embodiment, the chemical communication system may be used to communicate information about the fluid regime in the wellbore. For example, a tracer may be released multiple times to travel uphole toward the detection system. The measured value of each release may be compared against the measured value of another release. If the measured values of the releases are consistent, then it may be an indication that the fluid regime in the wellbore is laminar. However, if the measured values of the releases vary, then it may be an indication that the fluid regime in the wellbore is turbulent or an indication that a leakage has occurred.

In another embodiment, a method of communicating a wellbore parameter from a downhole tool includes providing a plurality of tracers to represent a code for communicating a value of the wellbore parameter, wherein the code includes a plurality of code elements and wherein each code element is represented by a tracer or a combination of different tracers; measuring the value of the wellbore parameter using a sensor; correlating the measured value of the wellbore parameter to a code element; releasing the tracer or combination of different tracers representing the code element to travel upstream; detecting presence of the tracer or combination of different tracers; and determining the specific value or range of values of the wellbore parameter from the detected tracer or combination of different tracers.

In another embodiment, a method of communicating a wellbore parameter from a downhole tool includes providing a plurality of tracer chemicals, whereby a code comprising a plurality of code elements correlates to a release of a single tracer chemical or a unique combination of a subset of the plurality of tracer chemicals to a specific value or a range of values of the wellbore parameter; measuring a value of the wellbore parameter using a sensor; ascribing the measured value to a code element; releasing one or more of the plurality of tracer chemicals corresponding to the code element; detecting the presence of the one or more of the plurality of tracer chemicals; and determining the specific value or range of values of the measured wellbore parameter from the detection of the one or more of the plurality of tracer chemicals.

In one or more of the embodiments described herein, ascribing the measured value to a code element is performed downhole.

In one or more of the embodiments described herein, detecting the presence of one or more of the plurality of tracer chemicals is performed at a surface of the wellbore.

In another embodiment, a method of communicating a wellbore parameter from a downhole tool includes generating a code comprising a plurality of code elements, wherein each discrete code element correlates a specific value or a range of values of the wellbore parameter to a unique pattern of releasing one or more of a plurality of tracer chemicals; providing the plurality of tracer chemicals at a location in a wellbore; measuring a value of the wellbore parameter using a sensor; ascribing the measured value to a discrete code element of the code; releasing one or more of the plurality of tracer chemicals in a unique pattern corresponding to the discrete code element; detecting the presence of the one or more of the plurality of tracer chemicals in the unique pattern; and determining the specific value or range of values of the measured wellbore parameter from the detection of the one or more of the plurality of tracer chemicals.

In one or more of the embodiments described herein, the pattern comprises a simultaneous release of two or more of the plurality of tracer chemicals.

In one or more of the embodiments described herein, the pattern comprises a sequential release of two or more of the plurality of tracer chemicals.

In another embodiment, a method of communicating a wellbore parameter from a downhole tool includes providing the plurality of tracer chemicals at a downhole location in a wellbore; measuring a value of the wellbore parameter using a sensor; releasing one or more of the plurality of tracer chemicals in a unique pattern corresponding to the measured value of the wellbore parameter; detecting at a surface location of the wellbore the presence of the one or more of the plurality of tracer chemicals in the unique pattern; and determining the specific value or range of values of the measured wellbore parameter from the detection of the one or more of the plurality of tracer chemicals.

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.

Claims

1. A method of communicating a wellbore parameter from a downhole tool, comprising:

providing a plurality of tracers for representing a value of the wellbore parameter;

measuring the wellbore parameter using a sensor;

correlating the wellbore parameter to a value represented by one or more of the plurality of tracers;

releasing the one or more of the plurality of tracers to travel upstream;

detecting presence of the one or more of the plurality of tracers; and

determining the wellbore parameter from the detected one or more of the plurality of tracers.

2. The method of claim 1, wherein each of the plurality of tracers is assigned a different value.

3. The method of claim 1, wherein each of the plurality of tracers comprises a chemical.

4. A system for communicating a wellbore parameter from a downhole tool, comprising:

a plurality of tracers for representing a value of the wellbore parameter;

a plurality of containers for storing the plurality of tracers;

a first sensor for measuring the wellbore parameter;

a downhole controller configured to correlate the wellbore parameter to one or more of the plurality of tracers and configured to release the one or more of the plurality of the tracers;

an second sensor for detecting presence of the one or more of the plurality of tracers; and

an uphole controller configured to determine the wellbore parameter from the detected one or more of the plurality of tracers.

5. The system of claim 4, wherein each of the plurality of tracers is assigned a different value.

6. The system of claim 4, wherein each of the plurality of tracers comprises a chemical.

7. The system of claim 4, wherein the container is pressurized.

8. The system of claim 4, wherein the first sensor is located downhole and the second sensor is located uphole.

9. A method of communicating a wellbore parameter from multiple downhole tools, comprising:

associating a first set of tracers to a first downhole tool;

associating a second set of tracers to a second downhole tool, wherein the first and second set of tracers represent a value of the wellbore parameter;

measuring the wellbore parameter using a sensor of the first downhole tool;

correlating the wellbore parameter to a value represented by one or more of the first set of tracers;

releasing the one or more of the first set of tracers to travel upstream;

detecting presence of the one or more of the first set of tracers;

determining the wellbore parameter from the detected one or more of the first set of tracers; and

determining the one or more of the first set of tracers was sent from the first downhole tool.

10. The method of claim 9, wherein each of the first set of tracers is assigned a different value.

11. The method of claim 9, wherein each of the first set of tracers comprises a chemical.

12-22. (canceled)

23. A method of communicating a wellbore parameter from a downhole tool, comprising:

providing a plurality of tracer chemicals, whereby a code comprising a plurality of code elements correlates to a release of a single tracer chemical or a unique combination of a subset of the plurality of tracer chemicals to a specific value or a range of values of the wellbore parameter;

measuring a value of the wellbore parameter using a sensor;

ascribing the measured value to a code element;

releasing one or more of the plurality of tracer chemicals corresponding to the code element;

detecting the presence of the one or more of the plurality of tracer chemicals; and

determining the specific value or range of values of the measured wellbore parameter from the detection of the one or more of the plurality of tracer chemicals.

24. The method of claim 23, wherein ascribing the measured value to a code element is performed downhole.

25. The method of claim 23, wherein detecting the presence of one or more of the plurality of tracer chemicals is performed at a surface of the wellbore.

26-29. (canceled)

30. A method of communicating a wellbore parameter from a downhole tool, comprising:

providing a plurality of tracers for representing a value of the wellbore parameter;

measuring the wellbore parameter using a sensor;

correlating the wellbore parameter to a value represented by a ratiometric amount of one or more of the plurality of tracers;

releasing the ratiometric amount of one or more of the plurality of tracers to travel upstream;

detecting presence of the ratiometric amount one or more of the plurality of tracers; and

determining the wellbore parameter from the detected ratiometric amount of one or more of the plurality of tracers.

31. The method of claim 30, further comprising releasing a calibration dosage of the plurality of tracers.

32. The method of claim 30, wherein each ratiometric amount of the plurality of tracers is assigned a different value.

33. The method of claim 30, wherein each of the plurality of tracers comprises a chemical.

34. The method of claim 30, wherein each tracer is released from a container storing the tracer.

35. The method of claim 34, further comprising opening the container using a mechanical actuator.

36-44. (canceled)