EP1584783B1 - Procédé de télémétrie dans un puits de forage - Google Patents

Procédé de télémétrie dans un puits de forage Download PDF

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Publication number
EP1584783B1
EP1584783B1 EP05013187A EP05013187A EP1584783B1 EP 1584783 B1 EP1584783 B1 EP 1584783B1 EP 05013187 A EP05013187 A EP 05013187A EP 05013187 A EP05013187 A EP 05013187A EP 1584783 B1 EP1584783 B1 EP 1584783B1
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EP
European Patent Office
Prior art keywords
downhole
tool
transmitter
transmitter unit
well
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Expired - Lifetime
Application number
EP05013187A
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German (de)
English (en)
Other versions
EP1584783A1 (fr
Inventor
Hubertus V Thomeer
Sarmad Adnan
Randolph J. Sheffield
Michael H. Kenison
Kevin J. Forbes
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Gemalto Terminals Ltd
Schlumberger Technology BV
Schlumberger Holdings Ltd
Original Assignee
Gemalto Terminals Ltd
Schlumberger Technology BV
Schlumberger Holdings Ltd
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US09/536,953 external-priority patent/US6333700B1/en
Application filed by Gemalto Terminals Ltd, Schlumberger Technology BV, Schlumberger Holdings Ltd filed Critical Gemalto Terminals Ltd
Priority claimed from EP01920692A external-priority patent/EP1274992B1/fr
Publication of EP1584783A1 publication Critical patent/EP1584783A1/fr
Application granted granted Critical
Publication of EP1584783B1 publication Critical patent/EP1584783B1/fr
Anticipated expiration legal-status Critical
Expired - Lifetime legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/26—Storing data down-hole, e.g. in a memory or on a record carrier
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/138—Devices entrained in the flow of well-bore fluid for transmitting data, control or actuation signals

Definitions

  • This invention relates to telemetry methods for use in wells, particularly in the drilling and completion of wells, such as oil and gas wells, and in the production of fluids from such wells.
  • Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation (i.e., a "reservoir") by drilling a well that penetrates the hydrocarbon-bearing formation. Once a wellbore has been drilled, the well must be "completed” before hydrocarbons can be produced from the well.
  • a completion involves the design, selection, and installation of tubulars, tools, and other equipment that are located in the wellbore for the purpose of conveying, pumping, or controlling the production or injection of fluids. After the well has been completed, production of oil and gas can begin.
  • tubular members such as casing, production tubing, landing nipples, and gas lift mandrels
  • flow control devices such as gas lift valves, subsurface safety valves, and packers
  • other equipment such as perforation guns.
  • a wireline retrievable subsurface safety valve can be lowered into a wellbore on a wireline to be installed in a particular landing nipple. If multiple landing nipples are located in the wellbore, generally the uppermost one must have the largest inner diameter, and each succeeding lower nipple must have a smaller inner diameter, so that the valve may be placed at the desired depth in the well. This requires the use of multiple sizes (i.e., inner diameters) of landing nipples, as well as corresponding sizes of safety valves.
  • this technique for installing and/or activating downhole tools in a wellbore works, it can be complex and cumbersome in certain instances.
  • WO 86/04365 discloses a telemetry system for a well, in which system a receiver is lowered into a well on a flexible line into proximity with a transmitter coupled to a sensor. The transmitter transmits a signal representative of a well parameter sensed by the sensor to the receiver, and the signal then passed over the flexible line to the surface
  • a method of providing telemetry from downhole in a well to a surface operator comprising:
  • FIG. 1 shows one embodiment of the invention.
  • a segment of a tubing string 10 includes a first downhole structure 12, which in this embodiment is a landing nipple that has a hollow axial bore 14 therethrough.
  • the landing nipple 12 is attached at its upper end 15 to an upper tubular member 16, and at its lower end 17 to a lower tubular member 18, by threaded connections 20 and 22.
  • the landing nipple 12 has an inner diameter 24 that is defined by the inner surface of the nipple wall.
  • a recess 26 is formed in the inner surface of the nipple wall, and a non-acoustic transmitter unit, in this case a radio frequency identification transmitter unit 28, is secured therein.
  • the non-acoustic frequency identification transmitter unit 28, which is shown in more detail in Figure 2, stores an identification code and transmits a radio frequency signal corresponding to the identification code.
  • the landing nipple 12 can be made of any material suitable for downhole use in a well, such as steel.
  • a cap 30, which for example can comprise steel or a ceramic or composite material such as resin coated fibers can overlay the frequency identification transmitter unit 28 and preferably physically seal it from contact with well fluids. However, it should be understood that absence of contact between well fluids and the frequency identification transmitter unit is not critical to the invention.
  • the cap 30 is not essential.
  • FIG 3 shows a second downhole structure 32, in particular a wireline lock, which is adapted to work in conjunction with the landing nipple 12 of Figure 1.
  • This second downhole structure comprises a non-acoustic frequency receiver unit 34, in this case a radio frequency receiver unit, that receives frequency signals, such as the one transmitted by the frequency identification transmitter unit 28.
  • the receiver unit decodes the non-acoustic frequency signal to determine the identification code corresponding thereto, and compares the identification code to a preset target identification code.
  • the non-acoustic frequency receiver unit 34 receives the non-acoustic frequency signal transmitted by the identification transmitter unit 28, decodes that signal to determine the identification code, and compares the determined identification code to the target code. If the determined identification code matches the target identification code, the first downhole structure is actuated or installed in the desired physical proximity to the second downhole structure (or vice versa). In particular, locking tabs 36 are extended outwardly into corresponding locking recesses 38 in the inner diameter of the second downhole structure.
  • Figures 1, 2, and 3 show the first downhole structure (e.g., the landing nipple 12) as being secured at a given location in a subterranean wellbore, by connection to a tubing string.
  • the second downhole structure e.g., a tool such as a lock with flow control device or a depth locator
  • the first downhole structure with the frequency identification transmitter unit therein
  • the second downhole structure with the frequency receiver unit therein
  • first and second downhole structures are described as having either transmitter units or receiver units. Such description is intended for discussion purposes and not intended to limit the scope of the present invention. It should be appreciated that, depending upon the application, the first and second downhole structures can have both transmitter units and receiver units.
  • Suitable non-acoustic frequency identification transmitter units are commercially available. Suitable examples of radio frequency transmitter units include the Tiris transponders, available from Texas Instruments. These radio frequency identification transmitter units are available in hermetically sealed glass capsules having dimensions of approximately 31 x 4 mm, emit a radio frequency signal at about 134.2 kHz that can be read up to about 100 cm away, and can comprise a 64 bit memory. Of course, this is only one possible embodiment, and larger or smaller memories can be used, as well as other frequencies, sizes, package configurations, and the like. Suitable non-acoustic frequency receiver units are also commercially available, such as the Tiris radio frequency readers and antennas from Texas Instruments.
  • Tiris transponders available from Texas Instruments, are adapted to store a multi-bit code, for example, a digital code of 64 bits.
  • the transponder itself will typically include a coil, a chip storing the multi-bit code, and associated circuitry.
  • the transponders are generally of three types. The first type is preprogrammed by the manufacturer with a preselected multi-bit code. A second type would be sold by the manufacturer in an unprogrammed state, and the end user may program the multi-bit code permanently into the transponder. A third type may be programmed initially and then reprogrammed many times thereafter with different multi-bit codes. In the presently preferred embodiment, the transponder is programmed one time permanently, either by the manufacturer or by the end user.
  • the multi-bit code in such a device may not be changed for the life of the transponder.
  • a reprogrammable transponder may be used to advantage. For example, after the transponder is placed downhole, its multi-bit code may be updated to reflect certain information. For example, a transponder associated with a downhole valve may have its multi-bit code updated each time the valve is actuated to reflect the number of times the valve has been actuated. Or, by way of further example, the multi-bit code may be updated to reflect the status of the valve as being in an open or closed position.
  • Tiris radio frequency readers and antennae may be used to read the multi-bit code stored in a Tiris transponder.
  • the reader/antenna is typically powered by battery, although it may be powered by way of a permanent power source through a hardwire connection.
  • the reader/antenna generates a radio signal of a certain frequency, the frequency being tuned to match the coil in the transponder.
  • the radio signal is transmitted from the reader/antenna to the transponder where power from the signal is inducted into the coil of the transponder. Power is stored in the coil and is used to generate and transmit a signal from the transponder to the reader/antenna.
  • Power is stored in the coil of the transponder for a very short period of time, and the reader/antenna must be prepared to receive a return signal from the transponder very quickly after first transmitting its read signal to the transponder.
  • the transponder uses the power stored in the coil, the transponder generates a signal representative of the multi-bit code stored in the transponder and transmits this signal to the reader/antenna.
  • the reader/antenna receives the signal from the transponder and processes it for digital decoding. The signal, or its decoded counterpart, may then be transmitted from the reader antenna to any selected data processing equipment.
  • the multi-bit code stored in a transponder may be updated and rewritten while the transponder is downhole.
  • a reader/antenna unit may be used to read the multi-bit code from a transponder downhole and, if desired, the code stored in the transponder may then be updated by way of a write signal to the reprogrammable transponder.
  • the first downhole structure will comprise a tubular member having a hollow axial bore.
  • the non-acoustic frequency identification transmitter unit preferably is secured to this tubular member, for example in a recess in the wall of the tubular member, as shown in Figure 1.
  • the frequency identification transmitter unit preferably is imbedded in the tubular member (i.e., sunk into a space in the member, so that the surface of the tubular member is not substantially affected, as opposed to attaching the unit to an exterior surface of the tubular member whereby it would create a substantial protrusion on that surface).
  • suitable examples of such tubular members include landing nipples, gas lift mandrels, packers, casing, external casing packers, slotted liners, slips, sleeves, guns, and multilaterals.
  • a tubing string 50 can include joints of production tubing 52a, 52b, 52c, and 52d. Attached to these joints of tubing are a first landing nipple 54 and a second landing nipple 56, with frequency identification transmitter units 55 and 57 secured thereto.
  • a second downhole structure e.g., a wireline retrievable subsurface safety valve
  • it will detect and determine the identification code of each nipple 54 and 56. If it detects an identification code that does not match its target code, it will not actuate, and thus can continue to be lowered in the bore. When it detects an identification code that does match its target code, it will actuate, thus allowing the safety valve to be selectively installed/actuated at a desired located in the wellbore.
  • FIG. 5 Another embodiment, shown in Figure 5, is particularly useful in a multilateral well 70 that has a plurality of lateral bores 72, 74, and 76.
  • Each of these lateral bores is defined by a lateral tubing string 78, 80, and 82 branching off from a main borehole 83.
  • Each of these tubing strings comprises at least one first downhole structure (e.g., landing nipples 84, 86, and 88, each having radio frequency identification transmitter units 90, 92, and 94 secured therein) secured in a fixed, given location in the respective lateral borehole.
  • first downhole structure e.g., landing nipples 84, 86, and 88, each having radio frequency identification transmitter units 90, 92, and 94 secured therein
  • the radio frequency receiver unit therein When the second downhole structure (e.g., a wireline retrievable subsurface safety valve) is lowered down through the tubing string and into one of the laterals, the radio frequency receiver unit therein will detect the radio frequency signal emitted by the transmitter in any nipple within range, and will thus determine the identification code of each such nipple as is passes close to the nipple.
  • this embodiment allows a determination of which lateral borehole the valve has entered.
  • FIG. 13 Another embodiment, shown in Fig. 13, is particularly useful when an electrical submersible pump (ESP) is integrated into the tubing string in a Y-Block configuration, indicated generally as 200.
  • At least one identification transmitter unit 202 is located above the Y-Block such that as a second downhole structure (i.e., tool, pipe, coil, wireline, slickline, etc.) is lowered through the tubing string 204, it detects and determines the identification code of the transmitter unit 202. Based on the determination of the identification code, the second downhole structure can automatically adjust to avoid an inadvertent entry into the branch containing the ESP.
  • a second transmitter unit 206 can be provided below the Y-Block to serve as a positive indication that the second downhole structure has entered the correct branch.
  • suitable second downhole structures can be, for example, subsurface safety valves, as well as gas lift valves, packers, perforating guns, expandable tubing, expandable screens, flow control devices, and other downhole tools.
  • Other second downhole structures can include, among others, perforations, fractures, and shut-off zones, in which the transmitter is placed during well stimulation (such as fracturing) or well intervention (such as perforation) operations.
  • a tubing string will include two or more first downhole structures that are located at different depths in a wellbore. These first downhole structure could suitably be landing nipples, or they could simply be tubing joints having a transmitter unit mounted thereon or embedded therein.
  • a tubing string 120 in a well 122 comprises a plurality of joints 124 of tubing, each connected to the next end-to-end by a threaded connection.
  • a radio frequency identification transmitter unit (not visible in Figure 6A) is embedded in the wall of the tubing.
  • Figure 6B shows the placement of the transmitter unit 128 in the wall of a tubing joint 124. Therefore, the known length of each tubing joint and the transmitter unit at the end of each joint, with a unique identification code, permits relatively precise assessment of the depth at which the secondary structure is located. Thus, the identification codes of the various first downhole structures in effect correlate to the depth at which each is installed, and the ID codes detected by the second downhole structure as it is lowered through the borehole will provide an indication of the depth of the second downhole structure.
  • a similar use determines depth as described in the previous paragraph as a way of determining when a perforating gun (as the second downhole structure) is at the desired depth at which it should be fired to perforate tubing and/or casing.
  • the perforating gun 210 is lowered with a supporting structure 212 until the desired transmitter unit 214 in the first downhole structure 216 is reached.
  • the perforating gun 210 is dropped without use of a supporting structure, such that it free falls and fires automatically when it reaches the desired transmitter unit 214 in the first downhole structure.
  • the second downhole structure can be a downhole tool that is adapted to be raised or lowered in a wellbore.
  • the downhole tool preferably is attached to a supporting structure 40, such as wireline, slickline, coiled tubing, and drillpipe.
  • a supporting structure 40 such as wireline, slickline, coiled tubing, and drillpipe.
  • the second downhole structure 32 can be moved to different depths within the borehole by raising or lowering this supporting structure 40.
  • One common type of actuation of a downhole tool that can occur in response to a match between the determined ID code and the target ID code comprises locking the second downhole structure in a fixed position relative to the first downhole structure.
  • locking protrusions 36 on the tool 32 can move outward into locking engagement with locking recesses 38 on the inner diameter of a landing nipple 12, as shown in Figure 8.
  • the identification code indicates at least the inner diameter of the tubular member
  • the target identification code is predetermined to match the identification code of the desired size (e.g., inner diameter) tubular member in which the downhole becomes locked upon actuation.
  • FIG. 9A shows a second downhole structure (i.e., downhole tool 32) locked in place in a landing nipple 12 by locking protrusions 36 that engage locking recesses 38.
  • the locking protrusions can be extended outwardly a greater distance to engage locking recesses 38a on the landing nipple 12a and thereby secure the tool 12a in a fixed position in the well.
  • This further extension is actuated by the receiver unit in the second downhole structure determining the ID code (and thus the inner diameter of the first downhole structure) and the need for further extension of the locking protrusions 36. This allows the use of more standard equipment, and lessens the need to maintain an inventory of many different sizes and/or configurations of downhole equipment.
  • the first downhole structure comprises a tubular member 100 having an axial bore 102 therethrough.
  • the bore is defined by the inner surface of the tubular member, which has a generally circular inner diameter 104.
  • the tubular comprises a plurality of radio frequency identification transmitter units 106a, 106b, 106c, 106d, 106e, 106f, 106g, and 106h spaced about its inner diameter, preferably in a single cross-sectional plane.
  • each non-acoustic frequency identification transmitter transmits a non-acoustic frequency signal (e.g., a radio frequency signal) corresponding to a different identification code.
  • the frequency receiver unit 110 located in or on the tool determines the identification code of the transmitter unit 106 that is closest to it, and thereby determines the orientation of the first downhole structure relative to second downhole structure in the wellbore.
  • the first downhole structure comprises a movable sleeve 130 or valve closure member which has a first position and a second position (e.g., open and closed positions shown in Figures 11A and 11B, respectively).
  • the movable sleeve 130 exposes a first non-acoustic frequency identification transmitter unit 140 and occludes a second non-acoustic frequency identification transmitter unit 142 when the movable sleeve or valve closure member is in the first position (see Figure 11A).
  • the movable sleeve 130 occludes the first transmitter unit 140 and exposes the second transmitter unit 142 when the movable sleeve is in the second position (see Figure 11B).
  • a shifting tool can be used to move the movable sleeve 130 from the first position (see Figure 11A) to the second position (see Figure 11B).
  • the movable sleeve 130 can be moved from the second position (see Figure 11B) to the first position (see Figure 11A).
  • the first transmitter unit transmits a frequency signal corresponding to an identification code that is different than the signal and code for the second transmitter unit.
  • the determined identification code can be used to determine whether a valve closure member is in the open or closed position, or to determine whether a movable sleeve is in the up or down position.
  • This embodiment of the invention can provide a positive indication that actuation (e.g., of a subsurface safety valve) has occurred, and can guarantee that the valve is open or closed. Failsafe indications such as make before break or break before make as appropriate can be used to guarantee the correctness of this verification and indication information.
  • the first downhole structure is a downhole tool 150 that comprises a fishing neck 152, and the non-acoustic frequency identification transmitter unit 154 is secured to the fishing neck.
  • the second downhole structure is a fishing tool 160 having secured to it the non-acoustic frequency receiver unit 162.
  • the identification code determined by the receiver unit can be used to determine when the fishing tool is in close enough physical proximity to the fishing neck, and thus can be used to actuate the fishing tool when it is in a suitable position for engaging the fish.
  • Another embodiment makes use of a detachable, autonomous tool that can be released from the end of a supporting structure (e.g., coiled tubing, wireline, or completion hardware) while downhole or uphole, to then do some desired operation in another part of the well (e.g., spaced horizontally and/or or vertically from the point at which the tool separates from the supporting structure).
  • the tool can later seek the end of the supporting structure, for example to enable it to be reattached, by homing in on the signal response from a transmitter unit embedded in the end of the supporting structure.
  • the tool can act as a repeater, actuator, or information relay device.
  • the agents may be autonomous tools, transmitters, or receivers.
  • the first agent can transfer a signal command from its location of origin to the boundary of the first fluid to a second fluid.
  • the second agent can receive the signal command in the second fluid and respond to the signal command (for example by retrieving information or executing the command).
  • the second agent can transfer a signal back to the first agent.
  • This relay of signal commands or information between autonomous agents optimized for submersible operation in different density fluids can use multiple autonomous agents and perform across multiple fluid interfaces. This relay of signal commands or information between autonomous agents can extend up or down-hole, between horizontal and vertical wellbores, and between multilateral wellbores and the main wellbore.
  • Another embodiment uses the non-acoustic transmitter units to relay information from a downhole tool to a surface operator.
  • the downhole tool has monitors and records data such as temperature, pressure, time, or depth, for example.
  • the tool can also record data describing the position or orientation of a piece of equipment, such as whether a sliding sleeve is open or closed. Further, the tool can record data such as whether downhole tools and equipment have been installed or actuated.
  • the non-acoustic transmitter units can be dedicated to relaying a certain type of information or can be used to relay multiple data types. This enables the correlation of data such as the temperature and pressure at the time of detonation.
  • a microprocessor on the tool determines what information should be sent to the surface.
  • the pertinent information is then written to a read/write non-acoustic transmitter unit that is stored in the tool.
  • the transmitter units can be stored in the tool in a variety of ways. For instance, the transmitter units can be installed into a spring-loaded column, much like the ammunition clip in a handgun. Alternatively, the transmitter units can be stored around the perimeter of a revolving chamber. The manner in which the transmitter units are stored in the tool is not important, as long as the required number of tags are available for use and can be released to the surface.
  • the transmitter unit After the pertinent information is written to a transmitter unit, the transmitter unit is released from the tool. It should be noted that the transmitter unit can be released either inside or outside of the tool depending upon the tool and the method of deployment. In one embodiment, when the transmitter unit is released, it is picked up by circulating fluid and carried to the surface. The transmitter unit is interrogated by a data acquisition device at the surface, at which time the information stored on the transmitter unit is downloaded. The microprocessor on the tool repeats the process with the additional transmitter units as directed by its programming.
  • the non-acoustic transmitter units can be used to send information from an operator at the surface to a tool located in the well.
  • the transmitter unit is written to and released from the surface, circulated to the tool below, and returned to the surface. Once acquired by the tool, the information stored on the transmitter unit is downloaded for use by the microprocessor.
  • a wide variety of instructions can be relayed from surface and carried out by the tool. Examples of possible instructions include how much to open a valve and whether or not to enter a multi-lateral, for example.
  • the following example is illustrative of both tool-to-surface and surface-to-tool telemetry using the non-acoustic transmitter units to perform coiled tubing perforating. It should be noted that the example is equally applicable to other coiled tubing applications as well as applications using other conveyance systems (e.g., slickline, wireline, completion tools, drill strings, tool strings, etc.). As shown in Figure 15, a plurality of passive transmitter units 220 are located in collars along the production string 222 .
  • a downhole tool 224 having a non-acoustic receiver unit 226 , a temperature gauge 228 , a pressure gauge 230 , and a tool clock 232 is attached to the coiled tubing 234 and carries the perforating gun 236 .
  • the downhole tool 224 also has a spring-loaded column 238 of passive read/write transmitter units 240 .
  • a separate antenna 242 is used to write information to the transmitter units 240 .
  • fluid is pumped into the annulus between the production string 222 and the coiled tubing 234 , through the tool 224 , and up the coiled tubing 234 .
  • the identification number of the transmitter unit 220 in the collar is read and decoded by a microprocessor in the tool 224 .
  • the antenna 242 then writes the identification number to the bottom-most transmitter unit 240 in the spring-loaded column 238. Also written to the same transmitter unit 240 is the instantaneous measurements of temperature and pressure, as well as the current time, which is synchronized with a surface clock.
  • the transmitter unit 240 is released into the inner diameter of the coiled tubing 234 , and another read/write transmitter unit 240 is pushed into position by the spring.
  • the overall transmitter unit density approximates that of the fluid density, so the released transmitter unit 240 flows up the inner diameter of the coiled tubing 234 with the fluid.
  • the transmitter unit 240 reaches surface, the data is collected and the process is repeated for each collar having transmitter units 226 , making possible readings such as pressure versus well depth, temperature versus well depth, and coiled tubing depth versus well depth, for example.
  • a transmitter unit 240 at the surface can be loaded with instructions on where (e.g. relative to a particular collar) and when (e.g. specific time delay) to fire the perforating gun 236 .
  • the transmitter unit 240 can then be circulated in the fluid down to the tool 224 , and the instructions carried out by the microprocessor in the tool.
  • critical information such as temperature and pressure, can again be relayed to the surface by transmitter units 240 released from the tool 224 .
  • the non-acoustic transmitter units can be used autonomously without the necessity of a downhole tool.
  • the pumping fluid can be used to carry the transmitter units downhole and back to the surface through circulation.
  • the individual transmitter units can receive and store data from transmitter units located downhole in tools, pipe casing, downhole equipment, etc. Once returned to the surface, the transmitter units can be analyzed to determine various operating conditions downhole. Such use provides continuous monitoring of wellbore conditions.
  • the non-acoustic transmitter units are used to autonomously actuate or install downhole tools and equipment.
  • non-acoustic transmitter units are dropped down the wellbore affixed to a drop ball, for example.
  • the non-acoustic transmitter units fall into proximity of non-acoustic receiver units located on the downhole tools and equipment, if the transmitted signal matches a predetermined identification code, the downhole tools and equipment are installed or actuated.
  • both receiver units and transmitter units can be used to advantage being dropped down the wellbore.
  • a receiver unit affixed to a drop ball can carry information gathered from passing a transmitter unit affixed to the wellbore, tools, equipment, etc. and relay that information to a receiver unit located further downhole.
  • the non-acoustic transmitter units can be placed along the wellbore and correlated with formation or well parameters or completion characteristics at those locations.
  • a digital signature for the wellbore can be created to pinpoint depth in the wellbore.
  • Non-acoustic frequency identification units encoding equipment serial numbers
  • This organization could also maintain a database of downhole tool identification codes/serial numbers of all components manufactured. Such a list of serial numbers could be classified or partitioned to allow for easy identification of the type and rating of any particular downhole component.
  • Non-acoustic frequency transmitter units can store and transmit a signal corresponding to very large serial number strings that are capable of accommodating all necessary classes and ratings of equipment.

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  • Life Sciences & Earth Sciences (AREA)
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Claims (7)

  1. Procédé de télémétrie dans un puits de forage depuis le fond d'un trou vers un opérateur de surface, le procédé comprenant les étapes consistant à:
    (a) pourvoir une unité d'émetteur RF (220) dans une structure de fond ;
    (b) pourvoir un outil de fond (224) ayant une unité de récepteur RF (226), au moins un capteur de données (228, 230, 232), un microprocesseur, et stocker de manière libérable une pluralité d'unités de transmetteur RF (240) ;
    (c) déplacer l'outil de fond (224) à proximité suffisamment étroite de la structure de fond de manière à ce que l'unité de récepteur RF (226) puisse recevoir le signal RF transmis par l'unité de transmetteur RF (220) dans la structure de fond ;
    (d) écrire des données acquises à partir du au moins un capteur de données (228, 230, 232) vers une de la pluralité d'unités de transmetteur RF stockées de manière libérable (240), les données étant écrites par le microprocesseur ;
    (e) libérer ladite une unité des unités de transmetteur RF stockées de manière libérable (240) ; et
    (f) retourner à la surface ladite une unité des unités de transmetteur RF stockées de manière libérable (240).
  2. Procédé selon la revendication 1, dans lequel l'outil de fond (224) a une pluralité de capteurs de données (228, 230, 232), et au moins un des capteurs de données (228) fournit des mesures de température.
  3. Procédé selon la revendication 1 ou la revendication 2, dans lequel l'outil de fond a une pluralité de capteurs de données (228, 230, 232), et au moins un des capteurs de données (230) fournit des mesures de pression.
  4. Procédé selon l'une quelconque des revendications précédentes, dans lequel l'outil de fond a une pluralité de capteurs de données (228, 230, 232), et au moins un des capteurs de données (232) fournit des mesures de temps.
  5. Procédé selon l'une quelconque des revendications précédentes, dans lequel ledit outil de fond (224) est déplacé par des fluides du puits de forage.
  6. Procédé selon l'une quelconque des revendications 1 à 4, dans lequel ledit outil de fond (224) est déplacé par un outil de transport.
  7. Procédé selon l'une quelconque des revendications précédentes, dans lequel les unités de transmetteur RF (240) sont retournées avec des fluides du puits de forage.
EP05013187A 2000-03-28 2001-03-22 Procédé de télémétrie dans un puits de forage Expired - Lifetime EP1584783B1 (fr)

Applications Claiming Priority (5)

Application Number Priority Date Filing Date Title
US09/536,953 US6333700B1 (en) 2000-03-28 2000-03-28 Apparatus and method for downhole well equipment and process management, identification, and actuation
US536953 2000-03-28
US8124101A 2001-03-19 2001-03-19
US81241 2001-03-19
EP01920692A EP1274992B1 (fr) 2000-03-28 2001-03-22 Appareil et procede pour equipement de fond de puits et gestion de processus, identification et actionnement

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EP01920692A Division EP1274992B1 (fr) 2000-03-28 2001-03-22 Appareil et procede pour equipement de fond de puits et gestion de processus, identification et actionnement

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EP1584783B1 true EP1584783B1 (fr) 2007-08-08

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WO2014187346A1 (fr) * 2013-05-22 2014-11-27 中国石油化工股份有限公司 Système de transmission de données et procédé de transmission au sol de données de mesure de fond en cours de forage
CN105089644A (zh) * 2014-05-22 2015-11-25 中国石油化工股份有限公司 传输随钻井下测量数据至地面的数据传输系统及方法

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WO2008066391A1 (fr) * 2006-11-28 2008-06-05 Visuray As Appareil pour enregistrement de fond de puits autonome et transport de signal sans fil ainsi que procédé pour collecter des données de puits
EP2157278A1 (fr) * 2008-08-22 2010-02-24 Schlumberger Holdings Limited Systèmes télémétriques sans fil pour outils d'extraction
RU2578017C1 (ru) * 2015-02-10 2016-03-20 Общество с ограниченной ответственностью "Газпром добыча Кузнецк" Устройство для крепления и защиты погружных блоков системы телеметрии
US9828851B1 (en) 2016-07-13 2017-11-28 Saudi Arabian Oil Company Subsurface data transfer using well fluids

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GB1549307A (en) * 1976-09-07 1979-08-01 Shell Int Research Method and means for transmitting measuring data
AU5453986A (en) * 1985-02-11 1986-08-26 Comdisco Resources, Inc. Method and means for obtaining data representing a parameter of fluid flowing through a down hole side of an oil or gas well bore
US5365229A (en) * 1992-11-16 1994-11-15 Halliburton Logging Services, Inc. Adaptive telemetry system for hostile environment well logging

Cited By (6)

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WO2014187346A1 (fr) * 2013-05-22 2014-11-27 中国石油化工股份有限公司 Système de transmission de données et procédé de transmission au sol de données de mesure de fond en cours de forage
GB2533044A (en) * 2013-05-22 2016-06-08 China Petroleum & Chem Corp Data transmission system and method for transmitting downhole measurement-while-drilling data to ground
US9739141B2 (en) 2013-05-22 2017-08-22 China Petroleum & Chemical Corporation Data transmission system and method for transmission of downhole measurement-while-drilling data to ground
GB2533044B (en) * 2013-05-22 2017-12-13 China Petroleum & Chem Corp Data transmission system and method for transmission of downhole measurement-while-drilling data to ground
CN105089644A (zh) * 2014-05-22 2015-11-25 中国石油化工股份有限公司 传输随钻井下测量数据至地面的数据传输系统及方法
CN105089644B (zh) * 2014-05-22 2019-01-01 中国石油化工股份有限公司 传输随钻井下测量数据至地面的数据传输系统及方法

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