Abstract:
Apparatus and method for accurately logging a drill-stem test tool into place as the DST tool is conveyed by drill pipe or tubing to the desired location are provided. One aspect of the invention provides an apparatus for logging into place a drill stem test tool, comprising: a drill string comprising drill pipes or tubings; a drill stem test tool disposed on the drill string; an electromagnetic telemetry tool disposed on the drill string; and a gamma ray tool connected to the electromagnetic telemetry tool. Another aspect of the invention provides a method for logging into place a drill stem test tool disposed on a drill string, comprising: lowering a drill stem test tool, an electromagnetic telemetry tool and a gamma ray tool disposed on a drill string into a wellbore; producing a partial log utilizing the gamma ray tool while the drill stem test tool is moved adjacent a correlative formation marker; compare the partial log to a well log to determine a depth position adjustment; and adjust a position of the drill stem test tool according to the depth position adjustment.

Description:
BACKGROUND OF THE INVENTION  
         [0001]    1. Field of the Invention  
           [0002]    The present invention generally relates to a logging into place tool. More particularly, the present invention relates to a logging into place tool having a gamma-ray tool and an electromagnetic telemetry tool attached to a drill stem test string.  
           [0003]    2. Background of the Related Art  
           [0004]    A drill-stem test (DST) system is commonly used in connection with hydrocarbon exploration and exploitation. The primary purpose of the DST is to obtain a maximum stabilized reservoir pressure, a stabilized flow rate, and representative samples formation fluids and gasses. The hydrocarbon reservoir&#39;s potential is evaluated utilizing various reservoir engineering calculations and the collected data/information.  
           [0005]    Drill stem test systems commonly have a multi-section housing which contains or supports a number of test-related devices, which collectively may be referred to as the drill stem test tool or DST tool. The housing sections are formed with internal conduits which, when the housing sections are assembled, co-operate to define a network of fluid flow paths required for the testing procedure. The housing sections are assembled at the surface and then lowered on the end of the drill string (e.g., drill pipes or tubings) to the desired test depth corresponding to a prospective zone of interest.  
           [0006]    Inflatable (or otherwise expandable) packers carried by certain of the housing sections engage the wellbore to isolate a test region. A single packer may be provided if only the bottom of the wellbore is to be tested, but it is common practice to provide a pair of packers which permit a test region intermediate of the top and bottom of the wellbore to be isolated.  
           [0007]    For conventional testing, weight may be set down on the drill string to expand the packers against the wellbore. For inflate testing, a pump may be positioned in the drill-stem test string to pump wellbore drill fluid (commonly referred to as “mud”) into the packers for inflation. Once the packers are set, a test valve is opened to introduce a flow of fluid from the test region into one of the channels formed in the drill stem test string. Upon completion of the initial flow period, the test valve is then closed (i.e., shut-in) to allow the formation to recover and build back to its original shut-in pressure. Repetitive flows and shut-ins are routinely performed to gather additional reservoir evaluation data. The drill stem test system is then retrieved to permit interpretation of the recorded pressure and temperature data and analysis of the fluids and/or gas samples trapped by the DST tool during the flow period.  
           [0008]    Typically, the DST tool is conveyed downhole using tubing or drill-pipe to a prospective zone of interest based upon previously measured depth and formation correlation from open hole wireline logs, e.g., a gamma-ray well log. However, during the process of conveying the DST tool with tubing or drill-pipe, improper or inaccurate measurements of the length of the drill string may take place due to inconsistent lengths of collars and drill-pipes, pipe stretch, pipe tabulation errors, etc., resulting in erroneous placement of the DST tool. Thus, DST tests may be performed in the wrong zone of interest, and incorrect decisions may result as to whether the formations being tested is a hydrocarbon-bearing formation. Furthermore, repeating the drill-stem test may be very costly both in expenses and time.  
           [0009]    Therefore, a need exists for an apparatus and method for accurately logging a drill-stem test tool into place as the DST tool is conveyed by drill pipe or tubing to the desired location.  
         SUMMARY OF THE INVENTION  
         [0010]    Apparatus and method for accurately logging a drill-stem test (DST) tool into place as the DST tool is conveyed by drill pipe or tubing to the desired location are provided.  
           [0011]    One aspect of the invention provides an apparatus for logging into place a drill stem test tool, comprising: a drill string comprising drill pipes or tubings; a drill stem test tool disposed on the drill string; an electromagnetic telemetry tool disposed on the drill string; and a gamma ray tool connected to the electromagnetic telemetry tool.  
           [0012]    Another aspect of the invention provides a method for logging into place a drill stem test tool disposed on a drill string, comprising: lowering a drill stem test tool, an electromagnetic telemetry tool and a gamma ray tool disposed on a drill string into a wellbore; producing a partial log utilizing the gamma ray tool while the drill stem test tool is moved adjacent a correlative formation marker; compare the partial log to a well log to determine a depth position adjustment; and adjust a position of the drill stem test tool according to the depth position adjustment.  
           [0013]    Another aspect of the invention provides an apparatus for testing a well, comprising: a downhole system comprising a drill stem test tool disposed on a drill string and an electromagnetic telemetry tool having a gamma ray tool disposed on the drill string; and a surface system comprising a controller disposed in communication with the downhole system. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0014]    So that the manner in which the above recited features, advantages and objects of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings.  
         [0015]    It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.  
         [0016]    [0016]FIG. 1 is a schematic diagram of a well testing system incorporating a drill stem test tool, an electromagnetic telemetry tool having a gamma ray tool according to the invention.  
         [0017]    [0017]FIG. 2 is a schematic diagram of an electromagnetic telemetry tool having a gamma ray tool according to the invention.  
         [0018]    [0018]FIG. 3 is a schematic diagram of one embodiment of a test string incorporating an inflate straddle drill stem test tool having an electromagnetic telemetry tool and a gamma ray tool according to the invention.  
         [0019]    [0019]FIG. 4 is a schematic diagram of another embodiment of a test string incorporating an inflate bottom hole drill stem test tool having an electromagnetic telemetry tool and a gamma ray tool according to the invention.  
         [0020]    [0020]FIG. 5 is a schematic diagram of one embodiment of a well testing system having a downhole system and a surface system.  
         [0021]    [0021]FIG. 6 is a flow diagram illustrating one embodiment of a method for logging into place a drill stem test tool according to the invention. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0022]    [0022]FIG. 1 is a schematic diagram of a well testing system incorporating a drill stem test tool, an electromagnetic telemetry tool having a gamma ray tool according to the invention. The gamma ray tool and the electromagnetic telemetry tool instrumentation may be encapsulated in a pressure housing mounted within a drill-stem test tool. The well testing system  100  generally comprises a surface unit  110  and a downhole test string  120 . The surface unit  110  may include one or more processors, computers, controllers, data acquisition systems, signal transmitter/receiver or transceivers, interfaces, power supplies and/or power generators and other components. In one embodiment, the surface unit  110  is housed in a mobile truck. An antenna  112 , such as a metal ground stake or other receiving instrumentation may be disposed or driven into the ground and connected to the surface unit  110  to receive and/or transmit signals to and/or from components in the downhole test string  120 . In one embodiment, the antenna  112  is disposed at about 100 feet (radial distance) away from the surface unit  110  with another connection from the surface unit  110  to the Blow Out Preventor (BOP) or other electrically conductive path to the drill string. The downhole string  120  includes a plurality of drill-pipe or tubing  122 , an electromagnetic telemetry tool having a gamma ray tool attached thereon  124 , one or more packers  126  and a drill stem test (DST) tool  128 . The plurality of drill-pipe or tubing  122  are connected from the surface to extend to the other components of the test string downhole. The electromagnetic telemetry tool  124  includes a transceiver for communicating with the surface unit  110 . The one or more packers  126  provide a sealed section of the zone of interest in the wellbore to be tested.  
         [0023]    [0023]FIG. 2A is a schematic diagram of an electromagnetic telemetry tool having a gamma ray tool according to the invention. The electromagnetic telemetry tool  124  generally includes a pressure and temperature sensor  210 , a power ampifier  220 , a downlink receiver  230 , a central processing unit  240 , a gamma ray tool  250 , and a battery unit  290 . The electromagnetic telemetry tool  124  is selectively controlled by signals from the surface unit to operate in a pressure/temperature sensing mode which provides for a record of pressure versus time or in a gamma ray mode which records gamma counts as the DST tool is raised or lowered past a correlative formation marker. The record of gamma counts is then transmitted to surface and merged with the surface system depth/time management software to produce a gamma-ray mini-log which is later compared to the wireline open-hole gamma ray log to evaluate the exact drill stem test tool depth.  
         [0024]    The gamma ray tool  250 , shown in FIG. 2B, includes a radiation detector  258  for detecting naturally occurring gamma radiation from the formation. The detector  258  is of a type appropriate to the detection of gamma radiation and the production of an electrical signal corresponding to each detected gamma ray and having an amplitude representative of the energy of the gamma ray. The detector  258  includes a scintillation crystal or scintillator  260  which is optically coupled to a photomultiplier tube (PMT)  262 . The scintillator  260  may comprise a gadolinium-containing material, such as gadolinium orthosilicate that is suitably doped, for example with cerium, to activate for use as a scintillator. The quantity of cerium in terms of number of atoms is typically of the order of about 0.1% to about 1% of the quantity of gadolinium. The scintillator may comprise other materials, such as sodium iodide doped with thalium (Nal)(Tl), bismuth germanate, cesium iodide, and other materials.  
         [0025]    Electrical power for the gamma ray tool  250  is supplied from the battery unit  290 . The gamma ray tool  250  includes power conditioning circuitry (not shown) for feeding power at appropriate voltage and current levels to the detector  258  and other downhole circuits. These circuits include an amplifier  268  and associated circuitry which receives the output pulses from photomultiplier tube (PMT)  262 . The amplified pulses are then applied to a pulse height analyzer (PHA)  270  which includes an analog-to-digital converter which may be of any conventional type such as the single ramp (Wilkinson rundown) type. Other suitable analog to digital converters may be used for the gamma ray energy range to be analyzed. Linear gating circuits may also be employed for control of the time portion of the detector signal frame to be analyzed. Improved performance can be obtained by the use of additional conventional techniques such as pulse pile-up rejection.  
         [0026]    The pulse height analyzer  270  may assign each detector pulse to one of a number (typically in the range 256 to 8000) of predetermined channels according to its amplitude (i.e., the gamma ray energy), and produces a signal in suitable digital form representing the channel or amplitude of each analyzed pulse. Typically, the pulse height analyzer  270  includes memory in which the occurrences of each channel number in the digital signal are accumulated to provide an energy spectrum. The accumulated totals are then transferred via a buffer memory  272  (which can be omitted in certain circumstances) to the telemetry interface circuits  274  for transmission to the surface equipment.  
         [0027]    At the surface, the signals are received by the signal processing circuits, which may be of any suitable known construction for encoding and decoding, multiplexing and demultiplexing, amplifying and otherwise processing the signals for transmission to and reception by the surface equipment. The operation of the gamma ray tool  250  is controlled by signals sent downhole from the surface equipment. These signals are received by a tool programmer  280  which transmits control signals to the detector  258  and the pulse height analyzer  270 .  
         [0028]    The surface equipment includes various electronic circuits used to process the data received from the downhole equipment, analyze the energy spectrum of the detected gamma radiation, extract therefrom information about the formation and any hydrocarbons that it may contain, and produce a tangible record or log of some or all of this data and information, for example on film, paper or tape. These circuits may comprise special purpose hardware or alternatively a general purpose computer appropriately programmed to perform the same tasks as such hardware. The data/information may also be displayed on a monitor and/or saved in a storage medium, such as disk or a cassette. The surface system may also include a depth-measuring system for measuring a depth position of the drill string/tubing or a component on the drill string.  
         [0029]    [0029]FIG. 3 is a schematic of one embodiment of a test string incorporating an inflatable straddle, drill stem test tool having an electromagnetic telemetry tool and a gamma ray tool according to the invention. The test string  300  includes a plurality of drill pipe sections  302  that extend from the surface. A plurality of components may be attached to the test string to perform the drill stem test for particular well conditions. For example, the test string may comprise an inflatable straddle assembly for testing a particular section of the wellbore. In one embodiment, as shown in FIG. 3, the test string  300  includes the following components connected in order downward from the drill pipe sections  302 ; first drill collars  304 , a reversing sub  306 , second drill collars  308 , a pressure activated reverse circulating sub  310 , a cross over sub  312 , a fluid recovery recorder  314 , a hydraulic main valve  316 , a reservoir flow sampler  318 , an inside recorder carrier  320 , an electromagnetic telemetry tool with a gamma ray tool  322 , hydraulic jars  324 , a safety joint  326 , a pump  328 , a screen sub  330 , a valve section  332 , a back-up deflate tool  334 , a first inflatable packer  336 , a recorder carrier and flow sub  338 , a hanger sub  340 , a drill collar spacer  342 , a bypass receiver sub  344 , a second inflatable packer  346 , a clutch drag spring unit  348 , an electronic or mechanical recorder  350 , and a bull nose  352 . The embodiment shown in FIG. 3 may be modified to include additional components or detail as needed for particular types of tests. Also, additional packers may be disposed adjacent the packers  336  and/or  346  to provide enhanced seal to the wellbore.  
         [0030]    [0030]FIG. 4 is a schematic diagram of another embodiment of a test string incorporating an inflate bottom hole drill stem test tool having an electromagnetic telemetry tool and a gamma ray tool according to the invention. In the embodiment shown in FIG. 4, the test string  400  comprises an inflatable bottom hole assembly for testing a bottom section of the wellbore. The test string  400  includes the following components connected in order downward from drill pipe sections  402 ; first drill collars  404 , a reversing sub  406 , second drill collars  408 , a pressure activated reverse circulating sub  410 , a cross over sub  412 , a fluid recovery recorder  414 , Hydraulic Main Valve  416 , a reservoir flow sampler  418 , an inside recorder carrier  420 , an electromagnetic telemetry tool with a gamma ray tool  422 , hydraulic jars  424 , a safety joint  426 , a pump  428 , a screen sub  430 , a valve section  432 , a back-up deflate tool  434 , one or more inflatable packers  436 , a recorder carrier  438  and flow sub  439 , a drag spring extension sub  440 , a drill collar spacer  442 , a clutch drag spring unit  448 , an electronic or mechanical recorder  450 , and a bull nose  452 .  
         [0031]    [0031]FIG. 5 is a schematic diagram of one embodiment of a logging into place system. The logging into place system  500  includes a downhole system  510  and a surface system  530 . In relation to the embodiment shown in FIG. 1, and the downhole system  510  includes the downhole test string  120  as shown in FIG. 1. Referring to the block diagram in FIG. 5, the downhole system  510  includes a drill stem test string  511 , a gamma-ray tool  512 , central processing unit  514 , a modulator  516 , a pre-amplifier  518 , a power amplifier  520 , and a transmitter/receiver  522 . One or more of these components may be housed in the telemetry tool  124  (in FIG. 1). The DST string  511  provides for mechanical manipulation at surface to open and close downhole valves and also allow for surface manipulation in order to inflate the downhole pump in order to inflate packers against the wellbore. Housed within the DST string is the electromagnetic telemetry system with a gamma ray tool controlled by signals transmitted from the surface system. A command is transmitted from surface to downhole to start recording and storing to memory a record of gamma counts as the tool is conveyed up or down past a correlative marker (formation). As time and conveyed depth measurements are stored at surface by the surface system, the measurements are correlated to the downhole gamma counts after being transmitted. A mini gamma ray log is generated and compared to the wireline open-hole for drill-pipe conveyed depth versus the log depth from the original wireline open hole log. The DST tool is then positioned up or down relative to the correlated measured depth from the open hole log.  
         [0032]    Communication between the downhole system  510  and the surface system  530  may be achieved through wireless electromagnetic borehole communication methods, such as the Drill-String/Earth Communication (i.e.: D-S/EC) method. The D-S/EC method utilizes the drill string or any electrical conductor, such as the casing or tubing and the earth as the conductor in a pseudo-two-wire-transmission mode.  
         [0033]    The surface system  530  includes a receiving antenna  531 , a surface transmitter/receiver  532 , a preamplifier/filter  534 , a demodulator  536 , a digital signal processor  537 , a plurality of input/output connections or I/O  538 , and a controller  540 . The controller  540  includes a processor  542 , and one or more input/output devices such as, a display  546  (e.g. Monitor), a printer  548 , a storage medium  550 , keyboard  552 , mouse and other input/output devices. A power supply  554  and a remote control  556  may also be connected to the input/output  538 .  
         [0034]    [0034]FIG. 6 is a flow diagram illustrating one embodiment of a method  600  for logging into place a DST tool according to the invention. To begin the logging into place method  600 , the DST tool is conveyed downhole into the wellbore with the electromagnetic telemetry tool and gamma ray tool. A plurality of drill pipes or tubings are connected onto the drill string until the measured depth is reached. (step  610 ) As the drill string is lowered into the wellbore past the prospective correlative formation, the tool is stopped and a downlink command from the surface system is sent ordering the gamma ray tool to start recording data to memory. (step  620 ) The drill string is then raised, for example, at a rate of approximately 5 meters per minute, to record gamma counts as the gamma ray tool passes by differing lithologies. After a distance of approximately 30 meters has logged, the complete record of downhole gamma counts is transmitted to surface. (step  630 ) A partial log (or mini log) is generated by merging the recorded surface depth/time records with the downhole gamma count record. (step  640 ) The partial log is then compared to a previously produced well log (e.g., open-hole gamma-ray log) and correlated to the same marker formation. (step  650 ) As the open hole gamma-ray log is considered correct, a depth position adjustment, if necessary, is calculated based on the comparison of the partial log to the open hole gamma-ray log. The drill-string is moved up or down by adding or removing drill pipe(s) or tubing(s) to adjust the position of the DST tool. (step  660 ) After the DST tool has been logged into place at a correct depth, the drill stem test may commence.  
         [0035]    The drill stem test provides reservoir data under dynamic conditions, including stabilized shut-in formation pressures, flow pressures and rates. The DST also records temperature measurements and collects representative samples of the formation fluids. Additionally, the drill stem test also provides for data to calculate reservoir characteristics including but not limited to permeability, well bore damage, maximum reservoir pressure, reservoir depletion or drawdown, radius of investigation, anomaly indications, and other qualitative and quantitative information regarding the well.  
         [0036]    While the foregoing is directed to the preferred embodiment of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.