System and methods for detecting casing collars

A tubing conveyed casing collar locator system that detects the casing collars in a wellbore and acoustically transmits the information through the tubing to the surface where it is detected and processed in a surface processor. The system comprises a downhole tool which comprises downhole sensors, a signal processor with memory, a drive circuit, a battery pack, and a signal generator. The surface system comprises a surface processor, depth system, and acoustic signal transmitter/receiver. The downhole tool detects casing collars as the tool is moved through the collar and acoustically transmits the data or stores the data in downhole memory according to programmed instructions. In one embodiment, the tool compares sensor signals from production elements, such as valves, to stored sensor signatures to uniquely identify the downhole element. In one embodiment, the downhole tool changes operating modes in response to surface command.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to oilwell casing string joint locators, and more particularly, to a joint locator and methods for positioning a well tool connected to a length of coiled or jointed tubing in a well.

2. Description of the Related Art

In the drilling and completion of oil and gas wells, a wellbore is drilled into a subsurface producing formation. Typically, a string of casing pipe is then cemented into the wellbore. An additional string of pipe, commonly known as production tubing, may be disposed within the casing string and is used to conduct production fluids out of the wellbore. The downhole string of casing pipe is comprised of a plurality of pipe sections which are threadedly joined together. The pipe joints, also referred to as collars, have increased mass as compared to the pipe sections. After the strings of pipe have been cemented into the well, logging tools are run to determine the location of the casing collars. The logging tools used include a pipe joint locator whereby the depths of each of the pipe joints through which the logging tools are passed is recorded. The logging tools generally also include a gamma ray logging device which records the depths and the levels of naturally occurring gamma rays that are emitted from various well formations. The casing collar and gamma ray logs are correlated with previous open hole logs which results in a very accurate record of the depths of the pipe joints across the subterranean zones of interest and is typically referred to as the joint and tally log.

It is often necessary to precisely locate one or more of the casing pipe joints in a well. This need arises, for example, when it is necessary to precisely locate a well tool such as a packer or a perforating gun within the wellbore. The well tool is lowered into the casing on a length of tubing. The term tubing refers to either coiled or jointed tubing. The depth of a particular casing pipe joint adjacent or near the desired location at which the tool is to be positioned can readily be found on the previously recorded joint and tally log for the well. Given this readily available pipe joint depth information, it would seem to be a straightforward task to simply lower the well tool connected to a length of tubing into the casing while measuring the length of tubing inserted in the casing. Measuring could be performed by means of a conventional surface tubing measuring device. The tool is lowered until the measuring device reading equals the depth of the desired well tool location as indicated on the joint and tally log. However, no matter how accurate the tubing surface measuring device is, the true depth measurement is flawed due to effects such as tubing stretch, elongation due to thermal expansion, sinusoidal and helical buckling of the tubing, and a variety of other unpredictable deformations in the length of the tubing from which the tool is suspended in the wellbore. In addition, coiled tubing tends to spiral when forced down a well or through a horizontal section of a well.

A variety of pipe string joint indicators have been developed including slick line indicators that can produce drag inside the pipe string and wire line indicators that send an electronic signal to the surface by way of electric cable and others. These devices, however, either cannot be utilized as a component in a coiled tubing system or have disadvantages when so used. Wireline indicators do not work well in highly deviated holes because they depend on the force of gravity to position the tool. In addition, the wire line and slick line indicators take up additional rig time when used with jointed tubing.

Thus, there is a need for an improved joint locator system and method of using the tool whereby the locations of casing joints can be accurately determined, and the information transmitted to the surface, as the coiled or jointed tubing is lowered into a well.

SUMMARY OF THE INVENTION

The present invention provides a casing collar locator system and methods of using the casing collar locator system which overcomes the other shortcomings of the prior art.

The casing collar locator system of the present invention comprises a casing collar locator tool adapted to be attached to the end of a length of coiled or jointed tubing and moved within a pipe string as the tubing is lowered or raised therein. The casing collar locator tool is adapted to connect to other downhole tools which may include packers and perforating guns. A sensing system is disposed in the casing collar locator tool for detecting the increased mass of a pipe casing collar as the locator is moved through the pipe casing collar and for generating an electric output signal in response thereto. An electronic system detects the sensor electric signal and activates an acoustic signal generator to create a surface detectable acoustic signal transmitted through the coiled or jointed tubing related to the location of the pipe casing collar. A surface receiver detects the acoustic signal and transmits the signal to a surface processor. A surface processor receives a continuous signal from a surface tubing depth measuring system and correlates the depth measurement with the received acoustic signals and stores this information to provide graphical and tabular outputs representative of the casing collar locations.

In an alternate mode, the casing collar locator tool is programmed at the surface, before insertion into the wellbore, to store the casing collar indication in downhole memory and to transmit the information to the surface after a programmed time delay has expired.

In another embodiment, a surface acoustic transducer system is adapted to send acoustic command signals to and receive acoustic signals from an acoustic casing collar tool. The casing collar tool is adapted to receive the surface generated command signals and to thereby act according to instructions in the processor of the casing collar tool.

Methods of using the above-described casing collar locator are also provided. The methods basically comprise connecting a casing collar locator tool of this invention to the end of a length of tubing. The casing collar locator automatically generates a surface detectable acoustic signal in the tubing each time the casing collar locator moves through a pipe casing collar. The depth of the casing collar locator and the surface acoustic signal detector are continuously measured, and the measured depths of the casing collar locator corresponding to the detected acoustic signal are recorded to produce an accurate record of the depth of each detected casing collar.

In an alternative method, the casing collar tool is programmed at the surface to store acquired casing collar data in downhole memory and to transmit this data to the surface after a programmed time delay. The casing collar tool is attached to the end of a length of coiled or jointed tubing and the tubing is run into the hole. As the tool is passed through each casing collar, the casing collar sensor generates an electrical signal which is stored in downhole memory as a function of time. Concurrently, a surface depth sensor measures and transmits this depth data to a surface processor. After a surface programmed time delay has expired the data in downhole memory is acoustically transmitted to the surface as a function of time, detected by the surface receiver and sent to the surface processor. The surface processor generates casing collar depth information according to programmed instructions.

In another method, a prior casing collar log is entered into the downhole tool memory along with a desired predetermined location as indicated by the number of collars traversed. The casing collar tool is run into the hole and senses each collar traversed. When the number of collars traversed matches the predetermined location, the tool transmits a signal to the surface, thereby allowing accurate tool placement downhole.

In another embodiment, a method for determining the location of downhole production elements is described. Existing casing collar sensor signatures of various production elements are stored in a memory module of a signal processor in the acoustic casing collar locator tool. The signatures are unique to each kind of element such as packers, valves, gravel pack screens, and other production elements. The casing collar tool is run in the hole on a tubing string moves past a production element, thereby generating an electric signal from the casing collar sensor. The casing collar sensor signal is compared to the stored signature signals using a technique such as cross correlation thereby determining the type of downhole element sensed. The locator tool sends an encoded acoustic signal to the surface indicating the unique element sensed. The surface system correlates the downhole signal and a surface measured depth signal to develop a log of downhole production elements.

In yet another preferred embodiment, a method is described for locating a well tool by using a downhole production element as a locating benchmark. A specific element signature is loaded into the memory of the signal processor of the casing collar locator tool. The locator tool and a well tool are run into the hole. When the casing collar tool senses the preselected element, an acoustic signal is transmitted to the surface. The well tool may then be positioned a predetermined distance from the located production element.

Examples of the more important features of the invention have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto.

DESCRIPTION OF THE PREFERRED EMBODIMENT

After a well has been drilled, completed and placed into production, it is often necessary to perform additional work-over operations on the well such as perforating, setting plugs, setting packers and the like. Such work-over operations are often performed utilizing a tubing string. Here the term tubing refers to either a coiled tubing string or a threadedly jointed tubing string. Coiled tubing is a relatively small flexible tubing (commonly 1-3 inches in diameter), which can be stored on a reel. When used for performing well procedures, the tubing is passed through an injector mechanism and a well tool is connected to the end of the tubing. The injector mechanism pulls the tubing from the reel, straightens the tubing and injects it into the well through a seal assembly at the wellhead. Typically, the injector mechanism injects thousands of feet of the coiled tubing into the casing string of the well. A fluid may be circulated through the coiled tubing for operating the well tool or for other purposes. The coiled tubing injector at the surface is used to raise and lower the coiled tubing and the well tool during the downhole operations. The injector also removes the coiled tubing and the well tool as the tubing is rewound on the reel at the end of the downhole operations.

InFIG. 1, according to one embodiment, well5is schematically illustrated along with a coiled tubing injector40and a coiled tubing reel assembly10. The well5includes a wellbore15having a string of casing20cemented therein in the usual manner. The wellbore15is typically filled with a completion fluid17for maintaining adequate bottom hole pressure on any open hole sections. A length of coiled tubing25is inserted into the casing20. The coiled tubing25has an acoustic casing collar locator tool35attached to the bottom of the coiled tubing25. A well tool55is attached to the bottom of the acoustic casing collar locator35. It will be appreciated by those skilled in the art that the positions of the well tool55and the locator tool35may be interchanged without affecting the system operation. In addition, more than one well tool55may be attached to the locator tool35, either above or below the locator tool35. Alternatively, a string of jointed production tubing (not shown) may be installed inside the casing20, and the acoustic casing collar locator35run inside the production tubing.

The coiled tubing injector40is of a design known to those skilled in the art and functions to straighten the coiled tubing and inject it into the wellbore15by way of the wellhead45. A depth measuring sensor60, which may be a depth wheel known in the art, functions to continuously measure the length of the coiled tubing within the wellbore15and to provide that information to a surface processor65by way of depth cable70. As used here, the term depth refers to the measured depth or length of tubing inserted in the well. Those skilled in the art will realize that the measured depth, and hence the length of tubing, may be different from the vertical depth for wellbores that deviate from the vertical. Such deviated wellbores are common. The surface processor65may be a computer, or microprocessor, with memory capable of running programmed instructions. The processor65may also have permanent data storage and hard copy output capabilities. The surface processor65functions to continuously record the depth of the coiled tubing25and the acoustic casing collar locator35attached thereto. This depth information may also be recorded as a function of time and stored in the processor65. The processor65may be a stand alone unit or may be located in an enclosure attached to a coiled tubing skid (not shown) or truck (not shown) or any other suitable enclosure commonly used in the art.

Alternatively, threaded, jointed tubing (not shown) may be used with a conventional derrick system (not shown) to run the casing collar locator tool and a well tool into the hole. The casing collar locator and well tools are attached to the bottom of the jointed tubing and run into the hole. The jointed system may be operated the same as the coiled system with the exception of making up the jointed connections.

Referring toFIG. 2, the acoustic casing collar locator35is illustrated schematically. The acoustic casing collar locator35comprises a cylindrical mandrel135with a through bore to allow undisturbed flow through the coiled tubing25to the well tool55. The upper end of the mandrel135is adapted to connect to the lower end of the coiled tubing25. The ends of the mandrel are adapted to connect to the tubing25or the well tools55as required for a given operation. As indicated above, the multiple well tools55and the collar locator35may be attached to the end of the tubing25in any order suitable to carry out a particular operation. A housing130is adapted to sealably fit over the mandrel135and threadably engage a shoulder of the mandrel135, thereby creating an annular instrument section155between the mandrel135and the housing130which is sealed from fluid intrusion at either end by conventional elastomeric type seals (not shown).

Disposed within the instrument section155are a casing collar sensor125, a battery pack120, a signal processor115, a drive circuit110, and an acoustic signal generator105. The casing collar sensor125is a magnetic device, known to those skilled in the art, for detecting the increased mass of a casing collar30as the casing collar sensor125is moved through a casing collar30joint section. The casing collar sensor125generates an electric output signal in response to the increased mass of the casing collar30. This electrical signal is sensed by suitable circuitry in the signal processor section115. The signal processor115contains analog and digital circuitry (not shown), which may include a microprocessor and memory, adapted to power and sense the output of the casing collar sensor125and to store this information in the memory of the signal processor115. The signal processor115is in turn connected by electric wires (not shown), to the drive circuit110. The drive circuit110receives power from the battery pack120via electric wires (not shown). The battery pack is comprised of a plurality of batteries (not shown). The drive circuit110provides a signal adapted to properly actuate the acoustic signal generator105via electric wires, (not shown). The acoustic signal generator105consists of a plurality of piezoelectric ceramic elements107configured to impart an acoustic impulse to the mandrel135when the acoustic signal generator105is actuated by the drive circuit110. Alternatively, magnetostrictive elements (not shown) may be used to impart an acoustic signal into the tubing. The acoustic signal is transmitted through the coiled tubing25to the surface where, in one preferred embodiment, it is detected by acoustic signal receiver50disposed proximate the injector40such that the receiver50contacts the coiled tubing25as the coiled tubing25passes through the injector40, as described later. The signal processor115may be programmed to generate a pulse type signal or a continuous signal of predetermined frequency. The frequency may be selected depending on operational parameters such as depth, tubing size, coiled or jointed tubing or other pertinent parameters.

Referring toFIG. 3, in one preferred embodiment, the receiver50comprises a housing201that contains rolling elements205which are forced in contact with the coiled tubing25as it is injected in or out of the wellbore15lined with casing20. The rolling elements205may be spheres, cylindrical rollers, or wheels coupled to actuators202for holding the rolling elements205against the coiled tubing25. The actuators202may be mechanically, pneumatically, or hydraulically actuated. Attached to the housing201is an accelerometer215for sensing vibrations. The acoustic signal, transmitted through the coiled tubing, causes a vibrational response in the rolling elements205. The vibrational response is transmitted through the housing201and is sensed by the accelerometer215. The accelerometer215generates an electrical signal related to the transmitted acoustic signal from downhole. The accelerometer signal is conditioned and transmitted to the surface processor65.

In another preferred embodiment, seeFIG. 4, the acoustic signals are detected at the surface by receiver assembly300which is acoustically coupled to the coiled tubing25. The receiver assembly300comprises an enclosed fluid-filled reservoir303with end caps306,307which are each fitted with seals302suitable for moving the coiled tubing25through the reservoir303with minimal fluid leakage through the seals302. Any suitable sliding seal, including packing materials, known in the art maybe used. The coiled tubing25is in contact with the fluid304inside the reservoir303. The fluid may be water or any other fluid capable of transmitting acoustic energy. As is known in the art, the acoustic signals traveling through the coiled tubing25are acoustically coupled to the fluid304in the reservoir303such that the acoustic signal in the coiled tubing25generates a pressure signal in the fluid304related to the acoustic signal in the coiled tubing25. A hydrophone301is positioned in the fluid304in the reservoir303to sense the acoustic related pressure signal in the fluid304and transmit an electrical signal to the surface processor65related to the pressure signal. The acoustic signal to pressure signal coupling efficiency is relatively low requiring a high sensitivity device such as hydrophone301to detect the pressure signal.

In another preferred embodiment, seeFIG. 5, a hydrophone400is located in the wellbore fluid17in the annular space between the coiled tubing25and the casing20such that the hydrophone400can sense the acoustic related pressure signals coupled to the wellbore fluid17from the coiled tubing25as the acoustic signal travels in the coiled tubing past the hydrophone400location. The hydrophone400transmits an electrical signal related to the pressure signal to the surface processor65.

The acoustic signal sensed by any of the previously described receivers is transmitted to the surface processor65via signal cable75. Signal cables70and75may be electrical, optical, or pneumatic type cables. Alternatively, wireless transmitters may be employed. Surface processor65continuously monitors the depth signal generated and transmitted to the processor65by the depth sensor60. The processor65operates according to programmed instructions to correlate the received acoustic signal with the depth of the acoustic casing collar locator35as measured by the depth sensor60. The depth-casing joint information is stored and/or printed out in graphical and tabular format as a log for use in operations. Alternatively, prior depth logs may be stored in the memory of the surface processor65and the stored collar locations compared to the detected collar locations for determining an accurate downhole tool placement between collars.

Referring toFIG. 6, in another preferred embodiment, a two-way surface acoustic transducer system600and a downhole acoustic casing collar locator95are both adapted to operate as transmitters and receivers to provide two-way communication between the surface and the downhole casing collar locator95. The two-way surface system600comprises a receiver602, which may be any of the previously described receivers, and an acoustic transmitter601. The acoustic transmitter may be a clamp on device using piezoelectric elements or alternatively magnetostrictive elements for imparting an acoustic signal into the coiled tubing25. The rest of the system is as described previously. Here, the surface processor65acts according to programmed instructions to direct the acoustic transducer system90to send commands to the downhole casing collar locator95. The downhole locator tool95may have additional receiver elements (not shown) and circuits (not shown) to enable enhanced reception of surface generated signals. The locator95acts according to programmed instructions in the downhole processor115. Typical surface to downhole commands include but are not limited to commands to (a) initiate transmission of downhole stored data, (b) transmit the number of collars traversed, (c) transmit when a particular production element is identified, (d) change downhole operating modes, for example, from the storage only mode to the transmission at every collar mode, and (e) changing acoustic transmission frequency to improve surface reception.

In another preferred embodiment, a gamma ray sensor (not shown) and associated circuits (not shown) for detecting natural gamma rays emitted from the subterranean formations may be included in the downhole system. Typically, the hydrocarbon bearing formations show increased gamma ray emission over non-hydrocarbon bearing zones. This information is used to identify the various production zones for setting production tools. Any gamma detector known in the art may be used, including, but not limited to, scintillation detectors and geiger tube detectors. The gamma ray detector may be incorporated in the instrument section155, or alternatively may be housed in a separate sub (not shown) and connected mechanically and electrically with the casing collar locator35using techniques known in the art.

The method of this invention for accurately determining the position of casing collars in a wellbore while moving coiled or jointed tubing within the casing comprises the following steps. An acoustic casing collar locator35is connected to the bottom end of coiled or jointed tubing25prior to running the tubing into the casing20in wellbore15. The tubing25with the acoustic casing collar locator35attached is run into the casing20and moved therethrough. As the acoustic casing collar locator35passes each casing collar30the acoustic casing collar locator35senses the casing collar30and transmits an acoustic signal through the tubing25to the surface where it is detected by the surface receiver50. The surface receiver50transmits an electrical signal to the surface processor65indicating the reception of the acoustic signal. The depth of the acoustic casing collar locator35is continuously measured by the depth sensor60and transmitted to the surface processor65. The surface processor65stores the received casing collar indication as a function of the depth indicated by the depth sensor60. Alternatively for jointed tubing, the length of each tubing joint can be manually entered into the surface processor65. The correlated casing collar depth information can be output in tabular or graphical format for use by the operator.

An alternative method comprises the steps of, programming the downhole signal processor115to store the detected casing collar signal as a function of time in memory in the signal processor115. Presetting the signal processor115at the surface to transmit the data after a preset time delay from starting downhole. Running the acoustic casing collar locator35into the hole to the approximate depth of interest quickly and then traversing the acoustic casing collar locator35through the section of interest at a slower rate. Storing the signal indicating detection of the casing collars in downhole memory as a function of time. Concurrently measuring and storing depth data from the depth sensor60in the surface processor65as a function of time. Stopping the movement of the coiled tubing25when the preset time delay expires, and transmitting the downhole stored data to the surface by activating the signal generator105. Processing the time interval between the received signals with the surface processor65and correlating the tubing speed as indicated by the surface depth sensor60to determine the distance between collars, thereby allowing accurate placement of a well tool55.

Another alternative method comprises, determining from a prior casing collar log, the number of collars to be traversed to a predetermined location. Storing the number of collars in the memory of the downhole signal processor115. Preprogramming the acoustic casing collar locator35to send a signal when the predetermined number of collars30are sensed. Running the acoustic casing collar locator35into the hole and sensing the casing collars as the casing collar locator35moves past each collar30. Comparing the number of collars30sensed with the predetermined number in the downhole memory and sending a signal to the surface when the predetermined number of collars is equaled. Using the signal that a predetermined collar30is reached, to switch to a mode of transmitting a signal as each additional collar is traversed, thereby allowing an operator to accurately set a downhole tool55between collars30.

In another method, a casing collar locator tool is used to acquire the casing collar sensor signals as the sensor passes various distinctive downhole production elements, which include but are not limited to control valves, packers, gravel pack screens, and lateral kickoff hardware. The differences in geometries and relative masses of these downhole elements results in unique casing collar sensor signals, also called signatures, for each type of element. These element signatures may be stored in the memory of the downhole signal processor115of the casing collar locator35described previously. These signature signals are compared to the signals generated as the casing collar locator tool35is moved through the casing20using cross correlation or other signal comparison techniques known in the art. When a particular completion element is identified, the locator tool35sends a coded signal to the surface indicating which production element has been sensed. Techniques for encoding acoustic signals are well known in the art and are not discussed here further.

The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope and the spirit of the invention. It is intended that the following claims be interpreted to embrace all such modifications and changes.