Patent Description:
One type of well testing operation that may be performed is a Drill Stem Test (DST), where information about the hydrocarbon formation is derived from pressure data obtained downhole during the testing operation. <CIT> describes a testing procedure when formation includes upper and lower zones. A well contains a tubing string. Packers surrounding the tubing string above the upper zone and between the two zones prevent flow along the annulus around the tubing string. While testing the lower zone, fluid flow enters the tubing through perforations and goes to the surface. At that stage there are no perforations for fluid from the upper zone to enter the tubing string. After testing the lower zone, the tubing string is perforated to give access to the to the upper zone. <CIT> also describes testing procedure when there are upper and lower zones. During testing of the lower zone, fluid from that zone is allowed to flow to the surface. Apparatuses adjacent the upper and lower zones are hydraulically isolated by a remotely actuated intermediate valve in order to prevent the flow of hydrocarbon fluid from the lower zone to the upper zone.

Certain embodiments of the present disclosure are directed to a method of performing an operation in a wellbore. The method includes running a toolstring in a wellbore that extends from a surface and penetrates a hydrocarbon-bearing formation that includes an upper zone and a lower zone. The toolstring includes a plurality of tools to perform an operation in the wellbore, including first and second packers, first and second fluid valves, and a fluid flow device. The fluid flow device includes a cylindrical housing having a wall defining an internal passageway for an axial fluid flow through the housing. Fluid ports extend through the wall to provide a path for a radial fluid flow to exit the internal passageway when the ports are open. The method further includes positioning the toolstring in the wellbore so that the first packer and the second packer straddle the upper zone, the first fluid valve and the second fluid valve straddle the upper zone, and the fluid flow device is adjacent the upper zone. The first packer is set to create a fluid flow barrier between the upper zone and an annulus of the wellbore surrounding the toolstring. The second packer is set to create a fluid flow barrier between the upper zone and the lower zone. The first fluid valve is closed to prevent a fluid flow through the toolstring to the surface, and the second fluid valve and the ports of the fluid flow device are opened to create a closed path for the hydrocarbon fluid to flow from the lower zone and into the upper zone. The method also includes perforating the lower zone.

Further embodiments of the present disclosure are directed to a system for performing an operation in a wellbore. The system includes a hub device to control and monitor a downhole operation in a wellbore that extends from a surface and penetrates a hydrocarbon formation having an upper zone and a lower zone. The system also includes a toolstring having multiple downhole flow control tools located in the wellbore to open and close paths for flow within the well bore, a first packer to form a barrier to fluid flow outside the toolstring above the upper zone and a second packer to form a barrier to fluid flow outside the toolstring between the lower and upper zones. The system further includes wireless repeaters communicatively coupled to a wireless transmission medium extending between the hub device and the downhole tools. The wireless repeaters can communicate with respective downhole flow control tools and respond to a multiple hop query generated by the hub device. The multiple hop query includes multiple commands directed to targeted downhole flow control tools. The hub device can generate a multiple hop query that directs the targeted downhole flow control tools to create a closed fluid path for hydrocarbon fluids to flow from the lower zone and into the upper zone and prevent flow to the surface during the well operation.

Yet further embodiments of the present disclosure are directed to a method of testing a hydrocarbon well. The method includes deploying a test string in a wellbore that extends from a surface and penetrates a hydrocarbon bearing formation that includes an upper zone and a lower zone. The test string includes a tubing, downhole tools to perform activities associated with a well test and acoustic repeaters coupled to the tubing and acoustically coupled with the downhole tools. The method further includes deploying a hub device in the wellbore that is communicatively coupled with surface equipment via a wired transmission medium and communicatively coupled with the acoustic repeaters via an acoustic transmission medium. The method also includes generating, by the hub device, commands directed to the downhole tools that cause the downhole tools to create a closed loop fluid flow path for hydrocarbon fluids to flow from the lower zone and into the upper zone during the well test.

Certain embodiments are described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying drawings illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein. The drawings show and describe various embodiments of the invention.

In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

In the specification and appended claims: the terms "connect", "connection", "connected", "in connection with", and "connecting" are used to mean "in direct connection with" or "in connection with via one or more elements"; and the term "set" is used to mean "one element" or "more than one element". Further, the terms "couple", "coupling", "coupled", "coupled together", and "coupled with" are used to mean "directly coupled together" or "coupled together via one or more elements". As used herein, the terms "up" and "down", "upper" and "lower", "upwardly" and downwardly", "upstream" and "downstream"; "above" and "below"; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention.

There are many hydrocarbon reservoirs and wells where two or more zones were discovered during drilling and formation testing from which hydrocarbons may be produced. In many instances, the well operator decides to produce hydrocarbons from one zone at a time and plugs the other zones (e.g., the lower zones). Once the selected zone is depleted, the operator may desire to unplug the lower zones for testing.

Well testing generally involves the process of recovering reservoir information based on pressure data collected by downhole sensors. Information that can be recovered includes skin, effective permeability and information concerning the geology and connectivity of boundary systems as they expand away from the wellbore. One type of well test that is often performed is called a drill stem test (DST). Although well testing provides valuable information for the operator, the testing can be costly in terms of the time and equipment needed. In addition, the fluids produced during the testing can create environmental concerns.

To illustrate, during a well test, a pressure disturbance is created that can be recorded by a gauge that is located either downhole (to measure bottom hole pressure or BHP) or at the surface (to measure well head pressure or WHP). This pressure disturbance can be created through a process where the hydrocarbon reservoir is produced (referred to as "drawdown") and then shut in (referred to as "buildup"). Generally the well test is carried out using surface well test equipment. A typical well test may include multiple modes or phases, such as clean-up, initial build up, main flow and final build up. In the clean-up phase, the reservoir is drawn down with the goal of cleaning the perforations and clearing the wellbore of any drilling or completion fluids. During the build-up phases, the well is shut in to increase the bottom hole pressure. During the main flow phase, the well fluid is drawn down by opening the well at a constant rate with the effect of decreasing the bottom hole pressure.

Telemetry data obtained during the well test can provide information about both the well and the reservoir. For example, the production index and skin can be derived for the interval of the well being tested, and the average/effective permeability, heterogeneities (fractures, layering, properties), shapes and distances of boundaries, and average and initial pressures can be derived for the reservoir.

Performing a well test, such as a DST, requires a large amount of surface equipment and can present environmental challenges. For example, the draw down phase of the test involves the production of large amounts of fluid from the well. In existing well test systems, these fluids are stored in large storage tanks at the surface for later disposal. In locations where storage tanks are not available, the produced fluids are flared, thus releasing carbon dioxide to the atmosphere. Further, throughout the test, the surface test equipment collects and analyzes real-time telemetry data to verify the integrity of each phase of the test before proceeding to the next. Due to the large number of surface equipment needed (e.g., storage tanks and test equipment) and the complexity of the test equipment, well testing can be very costly.

The communication system used to convey telemetry data and commands during the well testing also introduces complexities and costs. Communication systems for transmitting information between the surface and downhole components in a well are faced with numerous challenges, some of which can be addressed by implementing a wireless communication system. One type of wireless communication system that can be deployed in a downhole environment is an acoustic communications system that uses an elastic medium as the communications path. The acoustic communication system can be used in multiple contexts, including testing, drilling or production operations, and can be used to transmit various types of information, such as telemetry information related to downhole measurements, tool status, actuation commands, etc. Generally, an acoustic communication system is considered for use when there is no apparent way to run a wired communications path between the communicating devices. The communicating devices may involve an operational team, where a computer (or control system) is used in the vicinity of the well (e.g., on a rig, waveglider, etc.) or at a remote location that is indirectly connected to a communication module connected to the acoustic network. In other implementations, the acoustic communication network can operate autonomously between the various oil and gas equipment.

In general, an acoustic communications network is composed of an arrangement of communication nodes in the form of acoustic modems that receive and transmit messages. The acoustic modems generally use a pipe string (or tubing) as the elastic transmission medium. The communication network is established by connecting a plurality of acoustic modems to tubing at axially spaced locations along the string. Each modem includes a transducer that can convert an electrical signal to an acoustic signal (or message) that is then communicated using the tubing as the transmission medium. An acoustic modem within range of a transmitting modem receives the acoustic message and processes it, including by demodulating and decoding the message. These modems are referred to as repeaters. A repeater's acoustic transducer and associated electronics can be packaged in a single cartridge that can be clamped to tubing in the wellbore The power source for the repeater can be a battery.

In many well testing applications, the repeaters are placed on the tubing at spaced apart intervals, such that approximately <NUM> repeaters would be used for a <NUM> meter well. Deploying this number of repeaters not only involves costly hardware and batteries, but also entails implementing complex network initiation and routing procedures and thus can be yet another factor contributing significantly to the cost and complexity of a well test.

Accordingly, embodiments disclosed herein are directed to well testing systems and methods. Embodiments of the disclosed system and method reduce the surface equipment needed for well testing, automate the well testing, simplify the acoustic communications network, and provide a closed loop system where the fluids produced during the test are not brought to the surface for storage or flaring but instead are disposed in a downhole zone, which can be a depleted zone, a dry zone or a producing zone. Consequently, the capital expenditure associated with well testing can be reduced and the surface equipment that would otherwise be used to handle the fluids produced during testing can be eliminated. Embodiments of the disclosed system and method can be used in many different applications, including for testing a multi-zone well, where at least a first zone previously has been depleted or found dry (or is even still producing) and a second lower zone is to be tested. It should be understood, however, that embodiments disclosed herein can be implemented in other applications, such as using a lower zone to stimulate and naturally fracture an upper zone.

An example of a well testing system <NUM>, such as a DST system, deployed in a wellbore <NUM> is shown schematically in <FIG>, with additional detail shown schematically in <FIG>. The wellbore <NUM> penetrates a hydrocarbon-bearing formation <NUM> which, in this example, includes a first upper zone <NUM> and a second lower zone <NUM>. As shown, a toolstring or test string <NUM> has been deployed in the wellbore <NUM>. In general, a toolstring can be divided in two sections: the major string, which is the longest part comprised mostly of the tubing that guides the flow of hydrocarbons from the reservoir to the surface; and the Bottom Hole Assembly (BHA) where the most sensitive equipment, such as sensors and gauges are located.

In the example of <FIG> and <FIG>, the test string <NUM> includes a tubing <NUM> and other pieces of test equipment, as will be described further below. In this example, before the test string <NUM> was deployed in the wellbore <NUM>, the upper zone <NUM> was either produced and depleted or found dry. In embodiments, the upper zone <NUM> can be re-perforated with wireline casing guns before testing, if desired. The upper zone <NUM> can also be a producing zone.

To perform the well test, the test string <NUM> is deployed in the wellbore <NUM>. The string <NUM> includes a variety of pieces of equipment, including a first packer <NUM> and a second packer <NUM>, tester valves <NUM> and <NUM>, a sliding sleeve device <NUM>, tubing pressure and temperature gauges 124a-c, annulus pressure and temperature gauges 126a-c within the annulus <NUM>, a downhole adjustable choke <NUM>, and various pieces of test equipment, such as fluid samplers <NUM> and flow meter <NUM>.

Packers <NUM> and <NUM> are set to straddle the upper zone <NUM>. The packers <NUM> and <NUM> are retrievable packers and can be a rotation-to-set packer (i.e., a mechanical packer) or a non-rotation-to-set packer that is enabled by wireless (e.g., acoustic) information, such as by activating an electrical rupture disc. The packers <NUM> and <NUM> are used to temporarily create a barrier between zones <NUM> and <NUM> and/or create a barrier between a zone <NUM> or <NUM> and annular well control fluid (e.g., mud). In the example shown, upper packer <NUM> serves to create a barrier between the annular well control fluid above the packer <NUM> and the upper zone <NUM> below the packer <NUM>. The lower packer <NUM> serves to create a barrier between the upper non-productive zone <NUM> and the lower zone <NUM> below the packer <NUM>.

After setting the packers <NUM> and <NUM>, the upper test valve <NUM> is to isolate the fluid flow from reaching the surface, thus enabling a closed loop flow path to be created between upper zone <NUM> and lower zone <NUM>. Upper test valve <NUM> can also be used at the end of the well testing to kill the well and pull the test string <NUM> from the wellbore <NUM>. The lower test valve <NUM> is used as the main valve during the well test to ensure the fluid flow from the lower zone <NUM> to the upper zone <NUM>. The lower test valve <NUM> also is used to perform the pressure build-up of the lower zone <NUM> during the build-up phase of the well test.

The sliding sleeve device <NUM> is positioned between the upper packer <NUM> and lower packer <NUM>. As shown in <FIG>, the sliding sleeve device <NUM> generally includes a sleeve <NUM> slidable relative to a cylindrical housing <NUM> having an internal axial passageway <NUM> through which fluid can flow in the axial direction. The housing <NUM> includes one or more openings or ports <NUM> that extend through the wall of the housing <NUM> to provide a fluid flow path in the radial direction between the internal axial passageway <NUM> and the exterior of the housing <NUM> and thus allows fluid to flow from lower zone <NUM> into upper zone <NUM>. The sleeve <NUM> is movable relative to the housing <NUM> between open and closed positions. In the open position of the sleeve <NUM>, the ports <NUM> are exposed, thus allowing fluid to flow between the interior passageway and the exterior of the sleeve device <NUM>. In the closed position of the sleeve <NUM>, the ports <NUM> are closed, thus isolating the interior passageway from the region exterior of the sleeve device <NUM>. In embodiments, the sleeve device <NUM> can be activated acoustically so that the sleeve <NUM> moves between open and closed positions (although other activation techniques can also be used, such as hydraulic activation).

In the example of <FIG> and <FIG>, after packers <NUM> and <NUM> are set to isolate zones <NUM> and <NUM>, and the upper test valve <NUM> is closed, the sliding sleeve device <NUM> can be acoustically activated to the open position so that lower zone <NUM> can be tested. In the open position, ports <NUM> are open to upper zone <NUM>, thus enabling fluid flow from lower zone <NUM> to upper zone <NUM>, as denoted by dashed arrow <NUM>.

The test string <NUM> also includes a variety of other acoustically enabled equipment to perform the well test, such as the pressure and temperature gauges 124a-c, 126a-c, the fluid samplers <NUM>, the downhole flowmeter <NUM>, and the downhole adjustable choke <NUM>. In general, the pressure and temperature gauges 124a-c, 126a-c are used to acquire reservoir pressure and temperature during the different phases of the well test. The gauges 124a-c, 126a-c also can be used to verify and confirm the status of various operations performed during the well test, such as setting/unsetting of packers <NUM> and <NUM>, opening/closing of test valves <NUM> and <NUM>, opening/closing of sliding sleeve device <NUM>, perforation of zone <NUM>, etc. As shown in <FIG>, gauges 124a-c, 126a-c can be deployed at three (or more) different levels along the tubing <NUM>: e.g., above upper test valve <NUM>, between the upper and lower test valves <NUM> and <NUM>, and below the lower test valve <NUM>.

Fluid samplers <NUM> can be used to collect fluid samples during the flow phase of the test in which fluid is flowing from the lower zone <NUM>. Flowmeter <NUM> can record and stream flow data in real time via the acoustic telemetry. Downhole choke <NUM> can be used to change the size of the choke during the fluid flow phase of the test. It should be understood that the toolstring <NUM> can include additional equipment or different equipment than the equipment described above, depending on the particular test being performed.

In embodiments, an acoustic communications system is employed to enable communications between surface equipment <NUM> and the various downhole tools that make up the test string <NUM>, including the transmission of telemetry and status data from the various gauges, samplers, valves, perforation guns, chokes, and so forth, as well as the transmission of commands from the surface equipment <NUM> to the downhole tools.

<FIG> schematically illustrates an example of an acoustic communications system <NUM> that can be used in conjunction with the test string <NUM> of <FIG> to perform a well test. As shown in <FIG>, the communications system <NUM> includes a plurality of repeaters <NUM> deployed at spaced intervals along the tubing <NUM>. In general, a repeater <NUM> is made of electrical and mechanical components that provide the ability to transmit and receive acoustic signals that are exchanged between the surface and the downhole equipment.

A schematic illustration of a repeater <NUM> is illustrated in <FIG>. Repeater <NUM> includes a housing <NUM> that supports an acoustic transceiver assembly <NUM> that includes electronics and a transducer <NUM> which can be driven to create an acoustic signal in the tubing <NUM> and/or excited by an acoustic signal received from the tubing <NUM> to generate an electrical signal. The transducer <NUM> can include, for example, a piezoelectric stack, a magneto restrictive element, and/or an accelerometer or any other element or combination of elements that are suitable for converting an acoustic signal to an electrical signal and/or converting an electrical signal to an acoustic signal. The repeater <NUM> also includes transceiver electronics <NUM> for transmitting and receiving electrical signals. Power can be provided by a power supply <NUM>, such as a lithium battery, although other types of power supplies are possible, including supply of power from a source external to the repeater <NUM>.

The transceiver electronics <NUM> are arranged to receive an electrical signal from and transmit an electrical signal to the downhole equipment, such as the gauges <NUM>, <NUM>, valves <NUM>, <NUM>, and so forth. The electrical signal can be in the form of a digital signal that is provided to a processing system <NUM>, which can encode and modulate the signal, amplify the signal as needed, and transmit the encoded, modulated, and amplified signal to the transceiver assembly <NUM>. The transceiver assembly <NUM> generates a corresponding acoustic signal for transmission via the tubing <NUM>.

The transceiver assembly <NUM> of the repeater <NUM> also is configured to receive an acoustic signal transmitted along the tubing <NUM>, such as by another modem <NUM>. The transceiver assembly <NUM> converts the acoustic signal into an electric signal. The electric signal then can be passed on to processing system <NUM>, which processes it for transmission as a digital signal to the downhole equipment. In various embodiments, the processing system <NUM> can include a signal conditioner, filter, analog-to-digital converter, demodulator, modulator, amplifier, encoder, decoder, microcontroller, programmable gate array, etc. The repeater <NUM> also can include a memory or storage device <NUM> to store data received from the downhole equipment so that it can be transmitted or retrieved from the modem <NUM> later. Yet further, the memory or storage device <NUM> can store instructions of software for execution by the processing system <NUM> to perform the various well or well test operations described herein.

Returning to the example of <FIG>, the acoustic communication system <NUM> has been simplified relative to conventional systems by reducing the number of repeaters <NUM> that otherwise would be deployed along the tubing <NUM>. More particularly, rather than deploy repeaters <NUM> along the entire length of the tubing <NUM>, a hub repeater <NUM> is lowered from the surface to the level of the bottom hole assembly and the upper zone <NUM>. The hub repeater <NUM> is deployed from the surface using a cable <NUM>, such as a wireline cable, a slickline or a fiber optic cable, that allows for non-wireless communications with the surface equipment <NUM>. The cable <NUM> also can provide power to the hub repeater <NUM>, thus eliminating the battery power source. Consequently, fewer power consumption limitations are placed on the hub repeater <NUM> so that it can incorporate higher computational power and storage capacity, providing for greater capabilities at a reduced cost.

In known systems, a conventional technique for actuating downhole tools and acquiring downhole data entails transmitting a single query directed to a specific target downhole and then waiting to receive a response from the target. This technique can be costly both in terms of speed and energy consumption.

Accordingly, embodiments described herein are directed to an efficient data harvesting technique, referred to here as "Multiple Hop Queries. " In accordance with the Multiple Hop Queries technique, the hub repeater <NUM> assumes a supervisory (or master role) in the telemetry toolstring. Hub repeater <NUM> initiates a query that is composed of multiple simple queries, where each simple query is intended for a specific tool. As an example, a multiple hop query ("MHQ") could include a "close tester valve" command directed to the tester valve <NUM>, an "obtain pressure data" request directed to a sensor <NUM>, <NUM>, and an "open sleeve" command directed to the sliding sleeve device <NUM>. The hub repeater <NUM> transmits the MHQ, which is then routed through the acoustic network <NUM> in accordance with a predetermined routing algorithm (which may be based, for example, on current noise conditions, currently available repeaters, a default route, etc.). Each repeater <NUM> along the route that receives the MHQ verifies whether the MHQ includes a simple query addressed to that repeater. If so, the repeater <NUM> dequeues the MHQ, processes the simple query, queues the response to the query into the payload of the MHQ, and then transmits the MHQ (with the response) in accordance with the routing algorithm. Once the MHQ reaches the final repeater <NUM> in the network <NUM>, the final repeater <NUM> compiles the responses into a final response message and directs the final response to the hub repeater <NUM>. The hub repeater <NUM> then can transmit the final response to the surface acquisition equipment <NUM>.

A simplified example of the MHQ harvesting technique is shown in <FIG>, in which the network <NUM> includes the master/hub repeater <NUM>, repeater(m-<NUM>) 202a, repeater(m) 202b, repeater(m+<NUM>) 202c, and repeater(m+k) <NUM> (not shown), each coupled to an acoustic transmission medium, such as the tubing <NUM>. In this example, the hub repeater <NUM> transmits an MHQ <NUM> that includes command(m) 222b, command(m+<NUM>) 222c, and command(m+k) <NUM>. Repeater(m-<NUM>) 202a receives the MHQ <NUM>, verifies that the MHQ <NUM> does not include a command directed to it, and forward the MHQ <NUM> according to the routing algorithm. Repeater (m) 202b receives the MHQ <NUM>, confirms that it includes a command(m) 222b directed to it, dequeues the MHQ <NUM> and processes the command(m) 222b, and then generates a response(m) 224b that it appends to the payload of the MHQ <NUM>. MHQ <NUM> is then acoustically transmitted in accordance with the routing algorithm. Repeater(m+<NUM>) 202c receives MHQ <NUM>, verifies that it includes a command(m+<NUM>) 222c, dequeues and processes the command(m+<NUM>) 222c, and then generates a response(m+<NUM>) 224c that it appends to the payload of MHQ <NUM>. MHQ <NUM> is then acoustically transmitted in accordance with the routing algorithm. This process continues until the multiple hop query <NUM> (with the appended responses <NUM>) reaches the final repeater(m+k) <NUM>. Repeater <NUM> compiles responses 224b-k into a message <NUM> that it then transmits back to the hub repeater <NUM>.

In embodiments, the MHQ technique illustrated in <FIG> can be used to implement well testing using the tool string <NUM> in <FIG> and <FIG>. Each of the components of the tool string <NUM> are interfaced to an acoustic telemetry network, such as the network <NUM> shown in <FIG>.

To perform a well test (e.g., a DST) using the tool string <NUM> of <FIG> and <FIG>, the network <NUM> of <FIG> and the MHQ technique of <FIG>, a set of operation modes can be predefined that correspond to each phase of the well test. During each phase, a set of known tasks will be performed that can be translated into an MHQ. As an example, the phases of a drill stem test can correspond to a Pre-Perforation Mode, a Flowing Mode, a Build-Up Mode, and a Well Killing (Bullheading) Mode, among others.

<FIG> illustrates a workflow <NUM> for an exemplary Pre-Perforation Mode. At block <NUM>, the DST string <NUM> and the hub repeater <NUM> have been run in the wellbore <NUM>. At block <NUM>, the hub repeater <NUM> generates and transmits on the acoustic telemetry network <NUM> an MHQ[A] that includes commands to "set packer <NUM>," "set packer <NUM>," "close tester valve <NUM>" and "open sliding sleeve device <NUM>". At block <NUM>, the hub repeater <NUM> generates and transmits an MHQ[B] that includes queries to get the status of packers <NUM> and <NUM>, tester valve <NUM> and sliding sleeve device <NUM>. At block <NUM>, the hub repeater <NUM> generates and transmits an MHQ[C] that includes queries to get the pressure data from annulus gauge 126a, tubing gauge 124a, annulus gauge 126b, tubing gauge 124b, annulus gauge 126c and tubing gauge 124c. At block <NUM>, the hub repeater <NUM> examines the responses received from MHQ[B] and MHQ[C] to determine whether the pressure data confirms the status of the tools. If the status is not confirmed, the hub repeater <NUM> sends a notification message to the surface equipment <NUM> and re-starts the process at block <NUM>. If the status is confirmed, then the DST string <NUM> is ready to perform perforation of lower zone <NUM> (block <NUM>), and the perforation guns (not shown) can be activated.

The next phase of the DST test corresponds to the Build-Up Mode, in which the lower zone <NUM> is shut in so that the bottom hole pressure can build up. An exemplary workflow <NUM> for the Build-Up Mode is illustrated in <FIG>. After perforation of lower zone <NUM> and any cleanup is complete (block <NUM>), the hub repeater <NUM> generates and transmits MHQ[B] and MHQ[C] in order to obtain the status of the various tools and the pressure data from the various gauges 124a-c, 126a-c (block <NUM>). At block <NUM>, the hub repeater <NUM> compares the responses received in response to the MHQ[B] and MHQ[C] to determine whether the pressure data confirms the status of the tools. If the status is not confirmed, the hub repeater <NUM> notifies the surface equipment <NUM> and re-starts the process at block <NUM>. If the status is confirmed, then the DST test is ready to build up the bottom hole pressure (block <NUM>).

At block <NUM>, the hub repeater <NUM> generates an MHQ[D] with multiple commands, including to close tester valve <NUM> and to change the rate at which pressure data is acquired from tubing gauge 124c and annulus gauge 126c. For example, the MHQ[D] may command the tubing and annulus gauges 124c, 126c to provide pressure data at a fast rate (e.g., <NUM> second) for an initial short interval of the build-up phase (e.g., <NUM> minutes), a slower rate (e.g., <NUM> seconds) for a second interval (e.g., <NUM> hour), and then a much slower rate (e.g., <NUM> minutes) during the remainder of the pressure build-up period (e.g., <NUM> hours). After transmitting MHQ[D], the hub repeater <NUM> waits a short period to allow the pressure to build (e.g., <NUM>-<NUM> seconds) (block <NUM>). Then, the repeater hub <NUM> generates an MHQ[E] requesting the status of valve <NUM> and pressure data from gauges 124c, 126c (block <NUM>). If the responses indicate that the tester valve <NUM> is closed and the pressure is building (block <NUM>), then the hub repeater <NUM> will stream the pressure data to the surface equipment <NUM> (block <NUM>). Otherwise, the hub repeater <NUM> notifies the surface <NUM> and re-starts the process at block <NUM>.

In embodiments, the hub repeater <NUM> can also be configured to detect any anomalies in the pressure build-up during the Build-Up Mode (e.g., a leak, plug, etc.) If an anomaly is detected, the hub <NUM> notifies the surface equipment <NUM>.

The next phase of the DST test corresponds to the Flow Mode. In the Flow Mode, the adjustable downhole choke <NUM> is set to a particular size and the tester valve <NUM> is opened so that fluid can flow from lower zone <NUM> and into upper zone <NUM> through the slidable sleeve device <NUM>. In this mode, the hub repeater <NUM> again generates MHQs to query the status of the downhole tools and to obtain pressure and/or flow data. The MHQs can include commands to vary the size of the choke <NUM> and, if desired, to acquire fluid samples.

At the end of the Flow Mode, the DST test proceeds to the Kill Well Mode. In this Mode, the hub repeater <NUM> generates an MHQ with multiple commands, such as "open tester valve <NUM>," "wait <NUM> seconds," "open tester valve <NUM>," "wait <NUM> seconds," "open sliding sleeve <NUM>," "wait <NUM> seconds," and "open choke <NUM> fully. " The hub repeater <NUM> can then generates an MHQ requesting the status of each of the tools to which the commands were sent. Hub repeater <NUM> can also generate an MHQ requesting pressure data from each of the gauges. If the pressure data confirms the status of the tools, then bullheading can be started to kill the well. Otherwise, the hub repeater <NUM> notifies the surface equipment <NUM> and re-starts the Kill Well Mode process.

In embodiments, the DST test (or any other well test) described above can be performed automatically (i.e., without user intervention). In the automatic mode, the surface system <NUM> can send an executable file to the hub repeater <NUM> that contains the well test program, with details of the various modes, including the durations and the mode parameters. The hub repeater <NUM> can then execute the program, including generating an MHQ to activate the tools required for each particular phase of a mode. Once the tools for the current phase or mode are activated, the hub repeater <NUM> can generate MHQs to obtain tool status and acquire telemetry data. Data obtained by the hub repeater <NUM> can then be sent to the surface system <NUM> for display and real-time interpretation.

In embodiments, the automatic mode can be interrupted by the well test operator. For example, an operator can interrupt the well test at any time and send a specific acoustic command to a specific downhole tool. The interruption can be for verification, program changes, troubleshooting or any other purpose. Further, the interruption mode can be temporary or permanent (i.e., cancelling the automatic execution of the well test program). If permanent, a new well test program can then be transmitted to the hub repeater <NUM> for execution.

Although embodiments have been described in the context of drill stem testing, it should be understood that the techniques can be used with other types of well tests or operations. Further, the test may include different or additional phases or modes than those described above, and the various actions taken in each phase can be different than those described above or may be performed in different orders. Yet further, it should be understood that the closed loop well test technique can be implemented using communication networks other than the acoustic communications network <NUM>. Still further, it should be further understood that the techniques described herein can be implemented in a variety of wireless communications systems, and that the physical layer of the communication is not limited to the acoustic telemetry system that has been described above.

Claim 1:
A method (<NUM>, <NUM>) of performing a drill stem test in a wellbore (<NUM>), comprising:
running (<NUM>) a toolstring (<NUM>) in the wellbore (<NUM>) that extends from a surface and penetrates a hydrocarbon-bearing formation, the formation including an upper zone (<NUM>) depleted or dry of a hydrocarbon fluid and a lower zone (<NUM>) containing a hydrocarbon fluid, wherein the toolstring (<NUM>) includes a plurality of tools to perform the drill stem test in the wellbore (<NUM>), the tools including:
a first packer (<NUM>) and a second packer (<NUM>);
a first fluid valve (<NUM>) and a second fluid valve (<NUM>); and
a fluid flow device, wherein the fluid flow device includes a cylindrical housing (<NUM>) having a wall defining an internal passageway (<NUM>) for an axial fluid flow through the housing (<NUM>), and a plurality of ports (<NUM>) extending through the wall to provide a path for a radial fluid flow to exit the internal passageway (<NUM>) when the ports (<NUM>) are open;
positioning the toolstring (<NUM>) in the wellbore so that the first packer (<NUM>) and the second packer (<NUM>) straddle the upper zone (<NUM>), the first fluid valve (<NUM>) and the second fluid valve (<NUM>) straddle the upper zone (<NUM>), and the fluid flow device is adjacent the upper zone (<NUM>);
setting (<NUM>) the first packer (<NUM>) to create a fluid flow barrier between the upper zone (<NUM>) and an annulus (<NUM>) of the wellbore (<NUM>) surrounding the toolstring (<NUM>);
setting (<NUM>) the second packer (<NUM>) to create a fluid flow barrier between the upper zone (<NUM>) and the lower zone (<NUM>);
closing (<NUM>) the first fluid valve (<NUM>) to prevent a fluid flow through the toolstring (<NUM>) to the surface;
opening (<NUM>) the second fluid valve (<NUM>) and the ports (<NUM>) of the fluid flow device to create a closed path for the hydrocarbon fluid to flow from the lower zone (<NUM>) and into the upper zone (<NUM>); and
perforating the lower zone (<NUM>),
wherein the toolstring (<NUM>) is operated in a plurality of modes during the drill stem test, including a pre-perforation mode in which status of the tools is verified (<NUM>), a fluid flow mode in which fluid flows from the lower zone into the upper zone, and a build-up mode (<NUM>) in which fluid pressure in the wellbore is built up.