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CROSS-REFERENCE OF RELATED CASES 
     This application claims the benefit under 35 U.S.C. §119 to U.S. Provisional Patent Application Ser. No. 60/225,439, entitled WELL HAVING A SELF-CONTAINED INTERVENTION SYSTEM, U.S. Provisional Patent Application Ser. No. 60/225,440, entitled “SUBSEA INTERVENTION SYSTEM” and U.S. Provisional Application Ser. No. 60/225,230, entitled “SUBSEA INTERVENTION,” all of which were filed on Aug. 14, 2000. 
    
    
     BACKGROUND 
     The invention generally relates to a well having a self-contained intervention system. 
     Subsea wells are typically completed in generally the same manner as conventional land wells. Therefore, subsea wells are subject to the same service requirements as land wells. Further, services performed by intervention can often increase the production from the well. However, intervention into a subsea well to perform the required service is extremely costly. Typically, to complete such an intervention, the operator must deploy a rig, such as a semi-submersible rig, using tensioned risers. Thus, to avoid the costs of such intervention, some form of “light” intervention (one in which a rig is not required) is desirable. 
     Often, an operator will observe a drop in production or some other problem, but will not know the cause. To determine the cause, the operator must perform an intervention. In some cases the problem may be remedied while in others it may not. Also, the degree of the problem may only be determinable by intervention. Therefore, one level of light intervention is to ascertain the cause of the problem to determine whether an intervention is warranted and economical. 
     A higher level of light intervention is to perform some intervention service without the use of a rig. Shutting in a zone and pumping a well treatment into a well are two examples of many possible intervention services that may be performed via light intervention. 
     Although some developments in the field, such as intelligent completions, may facilitate the determination of whether to perform a rig intervention, they do not offer a complete range of desired light intervention solutions. In addition, not all wells are equipped with the technology. Similarly, previous efforts to provide light intervention do not offer the economical range of services sought. 
     A conventional subsea intervention may involve use a surface vessel to supply equipment for the intervention and serve as a platform for the intervention. The vessel typically has a global positioning satellite system (GPS) and side thrusters that allow the vessel to precisely position itself over the subsea well to be serviced. While the vessel holds its position, a remotely operated vehicle (ROV) may then be lowered from the vessel to find a wellhead of the subsea well and initiate the intervention. The ROV typically is used in depths where divers cannot be used. The ROV has a tethered cable connection to the vessel, a connection that communicates power to the ROV; communicates video signals from the ROV to the vessel; and communicates signals from the vessel to the ROV to control the ROV. 
     A typical ROV intervention may include using the ROV to find and attach guide wires to the wellhead. These guidewires extend to the surface vessel so that the surface vessel may then deploy a downhole tool or equipment for the well. In this manner, the deployed tool or equipment follows the guide wires from the vessel down to the subsea wellhead. The ROV typically provides images of the intervention and assists in attaching equipment to the wellhead so that tools may be lowered downhole into the well. 
     The surface vessel for performing the above-described intervention may be quite expensive due to the positioning capability of the vessel and the weight and size of the equipment that must be carried on the vessel. Thus, there is a continuing need for an arrangement that addresses one or more of the problems that are stated above. 
     SUMMARY 
     In an embodiment of the invention, a system includes a subsea well and a carousel of tools. The carousel of tools is adapted to automatically and selectively deploy the tools in the well to perform an intervention in the well. 
     In another embodiment of the invention, a method includes halting the flow of fluid in a well and deploying a tool from within the well while the fluid is halted. The tool is allowed to free fall while the fluid is halted. The flow is resumed to retrieve the tool. 
     In yet another embodiment of the invention, a method includes injecting sensors into a fluid of a well and using the sensors to measure a property of the well. Data is retrieved from the sensors, and this data indicates the measured properties. 
     Advantages and other features of the invention will become apparent from the following description, drawing and claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWING 
         FIG. 1  is a schematic diagram of a subsea production system according to an embodiment of the invention. 
         FIG. 2  is a schematic diagram of a wellhead assembly according to an embodiment of the invention. 
         FIG. 3  is a schematic diagram of a tool carousel assembly according to an embodiment of the invention. 
         FIG. 4  is a flow diagram depicting a technique to deploy and use a tool from within the well according to an embodiment of the invention. 
         FIGS. 5 ,  6 ,  7  and  8  are schematic diagrams depicting deployment and retrieval of tools according to different embodiments of the invention. 
         FIG. 9  is an electrical schematic diagram of a free flowing sensor according to an embodiment of the invention. 
         FIG. 10  is a schematic diagram of a system that includes a tractor deployed permanently inside a well according to an embodiment of the invention. 
         FIG. 11  is a schematic diagram depicting use of the tractor according to an embodiment of the invention. 
         FIG. 12  is a schematic diagram of a well depicting the tractor in a collapsed state and the release of a buoyant member to indicate the collapsed state according to an embodiment of the invention. 
         FIGS. 13 and 14  are schematic diagrams of sensors according to different embodiments of the invention. 
     
    
    
     DETAILED DESCRIPTION 
     Referring to  FIG. 1 , an embodiment of a subsea production system  12  in accordance with an embodiment of the invention includes a subsea field  8  of wells  10  (wells  10 A,  10 B,  10 C,  10 D and  10 E depicted as examples). Each well  10  includes a wellbore that extends into the sea floor and may be lined with a casing or liner. Each well  10  also includes a subsea wellhead assembly  22  (wellhead assemblies  22 A,  22 B,  22 C,  22 D and  22 E, depicted as examples) that is located at the well surface, which is the sea floor  15 . 
     Each wellhead assembly  22  may be connected to a conduit  26  (e.g., hydraulic control lines, electrical control lines, production pipes, etc.) that runs to a subsea manifold assembly  28 . Conduits  26 A,  26 B,  26 C,  26 D, and  26 E connect respective wellhead assemblies  22 A,  22 B,  22 C,  22 D and  22 E to the manifold  28 . In turn, various conduits  30  are run to a host platform  32  (which can be located at the sea surface, or alternatively, on land). The platform  32  collects production fluids and sends appropriate control (electrical or hydraulic) signals or actuating pressures to the wells  10 A- 10 E to perform various operations and may also communicate chemicals to chemical injection ports of the wellhead assemblies  22 . During normal operation, well fluids are delivered through the production tubing of each well and through the conduits  26 , manifold  28 , and conduits  30  to the platform  32 . 
     In some embodiments of the invention, the wellhead assembly  22  may include at least part of a system to perform light intervention, an intervention that includes self diagnosis of the associated well  10  and/or to remedy a diagnosed problem in the well. For example, as described below in some embodiments of the invention, the system that is described herein may test the well  10  at various depths, for example, to determine a composition of the well fluids that are being produced by the well. The results of this test may indicate, for example, that a particular zone of the well  10  should be plugged off to prevent production of an undesirable fluid. Thus, in this manner, the system may plug off the affected zone of the well. The testing of well fluid composition and the above-described setting of the plug intervention are just a few examples of the activities that may be performed inside the well  10  without requiring intervention that is initiated outside of the well  10 , as described below. 
     Referring to  FIG. 2 , in some embodiments of the invention, each wellhead assembly  22  may include a wellhead tree  52  that controls the flow of well fluids out of the well  10  and a blowout preventer (BOP)  36  that is connected to the wellhead tree  52  for maintaining a seal in the well  10  when tools are introduced into and retrieved from the well  10 . The wellhead assembly  22  also includes electronics  50  to, as described below, generally control the interventions inside the well  10 . In this manner, the electronics  50  may, for example, cause (as described below) a tool to be run downhole to perform a diagnosis of the well  10  for any potential problems. Based on the results of this diagnosis, the electronics  50  may then cause (as described below) another tool to be run downhole to take corrective action, or remedy the problem. 
     Referring also to  FIG. 3 , for purposes of making those tools available, the wellhead assembly  22  may include a tool carousel assembly  40  that is connected to the BOP  36 , for example. The carousel assembly  40  includes a carousel  63  that holds various tools  65 , such as tools to diagnosis the well  10  and tools to remedy problems in the well  10 . In this manner, the assembly  40  includes a motor  62  that rotates the carousel  63  to selectively align tubes  64  of the carousel  40  with a tubing  66  that is aligned with the BOP  36 . Each of the tubes  64  may be associated with a particular tool (also called a “dart”), such as a plug setting tool, a pressure and temperature sensing tool, etc. Thus, because the carousel assembly  40  is sealed into the well head assembly  22 , self diagnosis and light intervention may be performed within the well  10  without requiring intervention that is initiated outside of the well  10 . 
     In some embodiments of the invention, the electronics  50 , well tree  52  and tool carousel assembly  40  may perform a technique  70  to run a tool downhole to perform either tests on the well  10  or some form of corrective action. The initiation of the technique may be triggered, for example, by a periodic timer, by a command sent from the sea surface, or by a previous measurement that indicates intervention is needed. 
     In the technique  70 , the electronics  50  first stops (block  72 ) flow of well fluid from the well  10  by, for example, interacting with the well tree  52  to shut off the flow of fluids from the well  10 . Next, the electronics  50  selects (block  74 ) the appropriate tool  65  from the carousel assembly  40 . For example, this may include interacting with the motor  62  to rotate the carousel  63  to place the appropriate tool  65  in line with the tubing  66 . Thus, when this alignment occurs, the tool  65  is deployed (block  76 ) downhole. 
     Referring also to  FIGS. 5 and 6 , as an example, the electronics  50  may select a tool  65   a  to set a plug  94  downhole. Thus, as depicted in  FIG. 5 , once deployed, the tool  65   a  descends down a production tubing  90  of the well until the tool  65   a  reaches a predetermined depth, a depth that the electronics  50  programs into the tool  65   a  prior to its release. During this descent, the electronics  50  delays for a predetermined time to allow the tool to descend to the predetermined depth and perform its function, as depicted in block  78  of  FIG. 4 . Therefore, for the plug setting tool  65   a , when the tool  65   a  reaches the predetermined depth, the tool  65   a  sets the plug  94 , as depicted in  FIG. 6 . 
     After the expiration of the predetermined delay, the electronics  50  interacts with the well tree  52  to resume the flow of well fluids through the production tubing  90 , as depicted in block  80  of  FIG. 4 . Referring to both  FIGS. 4 and 6 , the flow of the fluids pushes the tool  65   a  back uphole. The tool  65   a  then enters the appropriate tubing  64  of the carousel  63 , and the carousel  63  rotates (under control of the electronics  50 ). The electronics  50  may then interact with the tool  65   a  to retrieve (block  82  of  FIG. 4 ) information from the tool  65   a , such as information that indicates whether the tool  65  successfully set the plug  94 , for example. 
     Besides indicating whether a run was successful, the tool  65  may be dropped downhole to test conditions downhole and provide information about these conditions when the tool returns to the carousel. For example,  FIG. 7  depicts a tool  65   b  that may be deployed downhole to measure downhole conditions at one or more predetermined depths, such as a composition of well fluid, a pressure and a temperature. The tool  65   b  includes a pressure sensor to  103  to measure the pressure that is exerted by well fluid as the tool  65   bs  descends downhole. In this manner, from the pressure reading, electronics  102  (a microcontroller, an analog-to-digital converter (ADC) and a memory, for example) of the tool  65   b  determines the depth of the tool  65   b . At a predetermined depth, the electronics  102  obtains a measurement from one or more sensors  103  (one sensor  103  being depicted in  FIG. 7 ) of the tool  65   b . As examples, the sensor  103  may sense the composition of the well fluids or sense a temperature. The results of this measurement are stored in a memory of the electronics  102 . Additional measurements may be taken and stored at other predetermined depths. Thus, when the tool  65   b  is at a position  108   a , the tool  65   b  takes one or more measurements and may take other measurements at other depths. 
     Eventually, the electronics  50  (see  FIG. 2 ) interacts with the well tree  52  to reestablish a flow to cause the tool  65   b  to flow uphole until reaching the position indicated by reference numeral  108   b  in  FIG. 7 . As the tool  65   b  travels past the position  108   b , a transmitter  104  of the tool  65   b  passes a receiver  106  that is located on the production tubing  90 . When the transmitter  104  approaches into close proximity of the receiver  106 , the transmitter  104  communicates indications of the measured data to the receiver  106 . As an example, the receiver  106  may be coupled to the electronics  50  to communicate the measurements to the electronics  50 . Based on these measurements, the electronics  50  may take further action, such as communicating indications of these measurements to a surface platform or sending a plug setting tool downhole to block off a particular zone, as just a few examples. 
       FIG. 8  depicts a tool  65   c  that represents another possible variation in that the tool  65   c  releases microchip sensors  124  to flow uphole to log temperatures and/or fluid compositions at several depths. In this manner, the tool  65   c  may travel downhole until the tool  65   c  reaches a particular depth. At this point, the tool  65   c  opens a valve  130  to release the sensors  124  into the passageway of the tubing  90 . The sensors  124  may be stored in a cavity  122  of the tool  65   c  and released into the tubing  90  via the valve  130 . 
     In some embodiments of the invention, the chamber  122  is pressurized at atmospheric pressure. In this manner, as each sensor  124  is released, the sensor  124  detects the change in pressure between the atmospheric pressure of the chamber  122  and the pressure at the tool  65   c  where the sensor  124  is released. This detected pressure change activates the sensor  124 , and the sensor  124  may then measure some property immediately or thereafter when the sensor  124  reaches a predetermined depth, such as a depth indicated by reference number  127 . As the sensors  124  rise upwardly reach the sea floor  15 , the sensors  124  pass a receiver  125 . In this manner, transmitters of the sensors  124  communicate the measured properties to the receiver  125  as the sensors  124  pass by the receiver  125 . The electronics  50  may then take the appropriate actions based on the measurements. Alternatively, the sensors  124  may flow through the conduits  26  to the platform  32  (see  FIG. 1 ) where the sensors  124  may be collected and inserted into equipment to read the measurements that are taken by the sensors. 
     In some embodiments, the sensors  124  may not be released by a tool. Instead, the sensors  124  may be introduced via a chemical injection line (for example) that extends to the surface platform. Once injected into the well, the sensors  124  return via the production line flowpath to the platform wherein the sensors  124  may be gathered and the measurement data may be extracted. Other variations are possible. 
       FIG. 9  depicts one of many possible embodiments of the sensor  124 . The sensor  124  may include a microcontroller  300  that is coupled to a bus  301 , along with a random access memory (RAM)  302  and a nonvolatile memory (a read only memory)  304 . As an example, the RAM  302  may store data that indicates the measured properties, and the nonvolatile memory  304  may store a copy of a program that the microcontroller  300  executes to cause the sensor  124  to perform the functions that are described herein. The RAM  302 , nonvolatile memory  304  and microcontroller  300  may be fabricated on the same semiconductor die, in some embodiments of the invention. 
     The sensor  124  also may also include a pressure sensor  316  and a temperature sensor  314 , both of which are coupled to sample and hold (S/H) circuitry  312  that, in turn, is coupled to an analog-to-digital converter  310  (ADC) that is coupled to the bus  301 . The sensor  124  may also include a transmitter  318  that is coupled to the bus  301  to transmit indications of the measured data to a receiver. Furthermore, the sensor  124  may include a battery  320  that is coupled to a voltage regulator  330  that is coupled to voltage supply lines  314  to provide power to the components of the sensor  124 . 
     In some embodiments of the invention, the components of the sensor  124  may contain surface mount components that are mounted to a printed circuit board. The populated circuit board may be encapsulated via an encapsulant (an epoxy encapsulant, for example) that has properties to withstand the pressures and temperatures that are encountered downhole. In some embodiments of the invention, the pressure sensor  316  is not covered with a sufficiently resilient encapsulant to permit the sensor  316  to sense the pressure. In some embodiments of the invention, the sensor  316  may reside on the outside surface of the encapsulant for the other components of the sensor  124 . Other variations are possible. 
     In other embodiments of the invention, the sensor may not contain any circuitry but may change in response to a detected pressure or temperature. For example,  FIG. 13  depicts a sensor  500  that may be formed from an encapsulant  503  that has a cavity  505  formed therein. In response to the pressure exceeding some predetermined threshold, the encapsulant  503  “pops” or collapses inwardly into the cavity  505 , thereby indicating the predetermined threshold was exceeded. The pressure threshold sensed by the sensor  500  may be controlled by varying the thickness of the encapsulant  503 , size of the cavity  505 , composition of the encapsulant  503 , gas content inside the cavity  505 , etc. 
     Another embodiment for a sensor  550  is depicted in  FIG. 14 . The sensor  550  may be used to detect a predetermined temperature. The sensor  550  may be formed from an encapsulant  553  that has a metal  551 , for example, contained therein. In response to the temperature of the sensor  550  exceeding some predetermined threshold, the metal  551  melts, thereby indicating the predetermined threshold was exceeded. The temperature sensed by the sensor  550  may be controlled by varying the thickness of the encapsulant  503 , composition of the metal  551 , composition of the encapsulant  553 , use of substitute materials for the metal  551 , etc. 
     Other variations for the sensor are possible. 
     In some embodiments of the invention, an arrangement that is depicted  FIG. 10  may be used inside the subsea well  10 . In this manner, a robot, such as a tractor  150 , may be located inside the production tubing of the well  10  to carry tools (such as a tool  152 ) about the well for purposes of diagnosing problems in the well and performing intervention in the well. The tractor  150  is permanently sealed inside the well  10 . 
     The tractor  150  may be tethered from a cable  154  that is in communication with the electronics  50  and/or an operator at the platform. The tool  152  that is moved by the tractor  150  may be a tool that is designated for use by the tractor  150  or a tool that is selected from the carousel assembly  40 , as just a few examples. As depicted in  FIG. 10 , the tractor  150  may be used to carry the tool  152  into a horizontal  95  tubing that lines a lateral well bore, for example. 
     Referring to  FIG. 11 , besides carrying a tool to a specific location, the tractor  150  may also be used to perform other tasks within the well  10 . For example, the tractor  150  may include a robotic arm  160  that the tractor  150  may use to move the sleeve on a valve  164 , for example. The tractor  150  may be used for other purposes. 
     Other variations are possible. For example, the tractor  150 , in some embodiments of the invention, is self-guided and self-powered by its own battery. In this manner, the tractor  150  may receive commands and power to recharge its battery when stationed at a docking station in the well. The tractor  150  may be dispatched to perform a particular task from the docking station without being connected to the docking station. After performing the function, the tractor  150  returns to the docking station. 
     It is possible that the tractor  150  may become lodged inside the production tubing during the performance of a given task. Should the tractor  150  become lodged to the point that it is not possible or feasible to dislodge the tractor  150 , the tractor  150  may collapse, as depicted in  FIG. 12  and fall to the bottom of the well bore. For the case where the tractor  150  becomes lodged and does not have a tethered cable connection, the tractor  150  may communicate by releasing a buoyant member  204  that propagates through the production tubing to the platform to indicate that the tractor  150  has become lodged and has assumed the collapsed position. 
     While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of the invention.

Summary:
A system includes a subsea well and a carousel of tools. The carousel of tools is adapted to automatically and selectively deploy the tools in the well to perform an intervention in the well. The flow of fluid in a well is halted, and a tool is deployed from within the well while the fluid is halted. The tool is allowed to free fall while the fluid is halted. The flow is resumed to retrieve the tool.