WO2011043763A1 - Procédé de forage de puits utilisant une réponse en temps réel avant des mesures de foret - Google Patents

Procédé de forage de puits utilisant une réponse en temps réel avant des mesures de foret Download PDF

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Publication number
WO2011043763A1
WO2011043763A1 PCT/US2009/059541 US2009059541W WO2011043763A1 WO 2011043763 A1 WO2011043763 A1 WO 2011043763A1 US 2009059541 W US2009059541 W US 2009059541W WO 2011043763 A1 WO2011043763 A1 WO 2011043763A1
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WO
WIPO (PCT)
Prior art keywords
wellbore
drilling
varying
drill
earth portion
Prior art date
Application number
PCT/US2009/059541
Other languages
English (en)
Inventor
Sara Shayegi
Derrick W. Lewis
Michael S. Bittar
James R. Lovorn
Craig W. Godfrey
Original Assignee
Halliburton Energy Services, Inc.
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
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to PCT/US2009/059541 priority Critical patent/WO2011043763A1/fr
Priority to EP10822500A priority patent/EP2486429A1/fr
Priority to PCT/US2010/051384 priority patent/WO2011044069A1/fr
Priority to US13/391,833 priority patent/US20120186873A1/en
Priority to AU2010303666A priority patent/AU2010303666A1/en
Publication of WO2011043763A1 publication Critical patent/WO2011043763A1/fr

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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
    • 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
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • 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
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells

Definitions

  • the present disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides a well drilling method utilizing real time response to ahead of bit measurements.
  • FIG. 1 is a schematic partially cross-sectional view of a well drilling system which can embody principles of the present disclosure.
  • FIG. 2 is an enlarged scale schematic partially cross- sectional view of a method embodying principles of the present disclosure.
  • FIG. 3 is a schematic partially cross-sectional view of the method, in which a formation boundary is detected prior to drilling into the formation boundary.
  • FIG. 4 is a reduced scale schematic cross-sectional view of the method, in which a wellbore is steered toward a desirable zone.
  • FIG. 5 is a schematic cross-sectional view of the method, in which the presence of another wellbore is
  • FIG. 1 Representatively and schematically illustrated in FIG. 1
  • Drilling fluid 18 commonly known as mud
  • a non-return valve 21 prevents flow of the drilling fluid 18 upward through the drill string 16 (e.g., when connections are being made in the drill string) .
  • Control of bottom hole pressure is very important in managed pressure drilling, and in other types of drilling operations.
  • the bottom hole pressure is very important.
  • Nitrogen or another gas, or another lighter weight fluid may be added to the drilling fluid 18 for pressure control. This technique is useful, for example, in
  • RCD rotating control device 22
  • the drill string 16 would extend upwardly through the RCD 22 for connection to, for example, a rotary table (not shown), a standpipe line 26, kelley (not shown), a top drive and/or other conventional drilling equipment.
  • the drilling fluid 18 exits the wellhead 24 via a wing valve 28 in communication with the annulus 20 below the RCD 22.
  • the fluid 18 then flows through drilling fluid return lines 30, 73 to a choke manifold 32, which includes
  • bottom hole pressure can be conveniently regulated by varying the backpressure applied to the annulus 20.
  • a hydraulics model can be used to determine a pressure applied to the annulus 20 at or near the surface which will result in a desired bottom hole pressure, so that an operator (or an automated control system) can readily determine how to regulate the pressure applied to the annulus at or near the surface (which can be conveniently measured) in order to obtain the desired bottom hole pressure.
  • Pressure applied to the annulus 20 can be measured at or near the surface via a variety of pressure sensors 36, 38, 40, each of which is in communication with the annulus.
  • Pressure sensor 36 senses pressure below the RCD 22, but above a blowout preventer (BOP) stack 42.
  • Pressure sensor 38 senses pressure in the wellhead below the BOP stack 42.
  • Pressure sensor 40 senses pressure in the drilling fluid return lines 30, 73 upstream of the choke manifold 32.
  • Another pressure sensor 44 senses pressure in the drilling fluid injection (standpipe) line 26. Yet another pressure sensor 46 senses pressure downstream of the choke manifold 32, but upstream of a separator 48, shaker 50 and mud pit 52. Additional sensors include temperature sensors 54, 56, Coriolis flowmeter 58, and flowmeters 62, 64, 66.
  • the system 10 could include only two of the three flowmeters 62, 64, 66. However, input from the sensors is useful to the hydraulics model in determining what the pressure applied to the annulus 20 should be during the drilling operation .
  • the drill string 16 preferably includes at least one sensor 60.
  • sensor (s) 60 may be of the type known to those skilled in the art as pressure while drilling (PWD), measurement while drilling (MWD) and/or logging while drilling (LWD) systems.
  • PWD pressure while drilling
  • MWD measurement while drilling
  • LWD logging while drilling
  • These drill string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of drill string characteristics (such as vibration, torque, rpm, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.), fluid characteristics and/or other measurements.
  • the drill string 16 may comprise wired drill pipe (e.g., having electrical conductors extending along the length of the drill pipe) for transmitting data and command signals between downhole and the surface or another remote location .
  • Additional sensors could be included in the system 10, if desired.
  • another flowmeter 67 could be used to measure the rate of flow of the fluid 18 exiting the wellhead 24
  • another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of a rig mud pump 68, etc.
  • Pressure and level sensors could be used with the separator 48, level sensors could be used to indicate a volume of drilling fluid in the mud pit 52, etc.
  • the output of the rig mud pump 68 could be determined by counting pump strokes, instead of by using flowmeter 62 or any other flowmeters.
  • separator 48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a "poor boy degasser"). However, the separator 48 is not necessarily used in the system 10.
  • the drilling fluid 18 is pumped through the standpipe line 26 and into the interior of the drill string 16 by the rig mud pump 68.
  • the pump 68 receives the fluid 18 from the mud pit 52 and flows it via a standpipe manifold 70 to the standpipe 26, the fluid then circulates downward through the drill string 16, upward through the annulus 20, through the drilling fluid return lines 30, 73, through the choke manifold 32, and then via the separator 48 and shaker 50 to the mud pit 52 for conditioning and recirculation.
  • the choke 34 cannot be used to control backpressure applied to the annulus 20 for control of the bottom hole pressure, unless the fluid 18 is flowing through the choke.
  • a connection is made in the drill string 16 (e.g., to add another length of drill pipe to the drill string as the wellbore 12 is drilled deeper), and the lack of circulation will require that bottom hole pressure be regulated solely by the density of the fluid 18.
  • the fluid 18 is flowed from the pump 68 to the choke manifold 32 via a bypass line 72 , 75 when a connection is made in the drill string 16 .
  • the fluid 18 can bypass the standpipe line 26 , drill string 16 and annulus 20 , and can flow directly from the pump 68 to the mud return line 30 , which remains in communication with the annulus 20 . Restriction of this flow by the choke 34 will thereby cause pressure to be applied to the annulus 20 .
  • both of the bypass line 75 and the mud return line 30 are in communication with the annulus 20 via a single line 73 .
  • the bypass line 75 and the mud return line 30 could instead be separately connected to the wellhead 24 , for example, using an additional wing valve (e.g., below the RCD 22 ) , in which case each of the lines 30 , 75 would be directly in communication with the annulus 20 .
  • Flow of the fluid 18 through the bypass line 72 , 75 is regulated by a choke or other type of flow control device 74 .
  • Line 72 is upstream of the bypass flow control device 74, and line 75 is downstream of the bypass flow control device .
  • Flow of the fluid 18 through the standpipe line 26 is substantially controlled by a valve or other type of flow control device 76.
  • the flow control devices 74, 76 are independently controllable, which provides
  • the flowmeters 64, 66 are depicted in FIG. 1 as being interconnected in these lines. However, the rate of flow through the standpipe line 26 could be determined even if only the flowmeters 62, 64 were used, and the rate of flow through the bypass line 72 could be determined even if only the flowmeters 62, 66 were used. Thus, it should be
  • system 10 it is not necessary for the system 10 to include all of the sensors depicted in FIG. 1 and described herein, and the system could instead include additional sensors, different combinations and/or types of sensors, etc .
  • a bypass flow control device 78 and flow restrictor 80 may be used for filling the standpipe line 26 and drill string 16 after a connection is made, and equalizing
  • the standpipe bypass flow control device 78 By opening the standpipe bypass flow control device 78 after a connection is made, the fluid 18 is permitted to fill the standpipe line 26 and drill string 16 while a substantial majority of the fluid continues to flow through the bypass line 72, thereby enabling continued controlled application of pressure to the annulus 20.
  • the flow control device 76 can be opened, and then the flow control device 74 can be closed to slowly divert a greater proportion of the fluid 18 from the bypass line 72 to the standpipe line 26.
  • a similar process can be performed, except in reverse, to gradually divert flow of the fluid 18 from the standpipe line 26 to the bypass line 72 in preparation for adding more drill pipe to the drill string 16. That is, the flow control device 74 can be gradually opened to slowly divert a greater proportion of the fluid 18 from the standpipe line 26 to the bypass line 72, and then the flow control device 76 can be closed.
  • the restrictor 80 could be integrated into a single element (e.g., a flow control device having a flow restriction therein), and the flow control devices 76, 78 could be integrated into a single flow control device 81 (e.g., a single choke which can gradually open to slowly fill and pressurize the standpipe line 26 and drill string 16 after a drill pipe connection is made, and then open fully to allow maximum flow while drilling) .
  • a single flow control device 81 e.g., a single choke which can gradually open to slowly fill and pressurize the standpipe line 26 and drill string 16 after a drill pipe connection is made, and then open fully to allow maximum flow while drilling
  • the individually operable flow control devices 76, 78 are presently preferred.
  • the flow control devices 76, 78 are at times referred to collectively below as though they are the single flow control device 81, but it should be understood that the flow control device 81 can include the individual flow control devices 76, 78.
  • the system 10 could include a backpressure pump (not shown) for applying pressure to the annulus 20 and drilling fluid return line 30 upstream of the choke manifold 32, if desired.
  • the backpressure pump could be used instead of, or in addition to, the bypass line 72 and flow control device 74 to ensure that fluid continues to flow through the choke manifold 32 during events such as making connections in the drill string 16.
  • additional sensors may be used to, for example, monitor the pressure and flow rate output of the backpressure pump.
  • connections may not be made in the drill string 16 during drilling, for example, if the drill string comprises a coiled tubing.
  • the drill string 16 could be provided with conductors and/other lines (e.g., in a sidewall or interior of the drill string) for transmitting data, commands, pressure, etc. between downhole and the surface (e.g., for communication with the sensor 60).
  • a controller 84 (such as a programmable logic controller or another type of controller capable of controlling operation of drilling equipment) is connected to a control system 86 (such as the control system described in international application serial no. PCT/US08/87686 ) .
  • the controller 84 is also connected to the flow control devices 34, 74, 81 for regulating flow injected into the drill string 16, flow through the drilling fluid return line 30, and flow between the standpipe injection line 26 and the return line 30.
  • the control system 86 can include various elements, such as one or more computing devices/processors , a
  • hydraulic model a wellbore model, a database, software in various formats, memory, machine-readable code, etc.
  • a wellbore model a database
  • software in various formats, memory, machine-readable code, etc.
  • the control system 86 is connected to the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 which sense respective drilling properties during the drilling
  • control system 86 can include software, programmable and preprogrammed memory, machine-readable code, etc. for carrying out the steps of the method 90 described above.
  • the control system 86 may be located at the wellsite, in which case the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 could be connected to the control system by wires or wirelessly. Alternatively, the control system 86, or any portion of it, could be located at a remote location, in which case the control system could receive data via satellite transmission, the Internet, wirelessly, or by any other appropriate means.
  • the controller 84 can also be connected to the control system 86 in various ways, whether the control system is locally or remotely located.
  • data signals from the sensors 36 , 38 , 40 , 44 , 46 , 54 , 56 , 58 , 60 , 62 , 64 , 66 , 67 are transmitted to the control system 86 at a remote location, the data is analyzed there (e.g., utilizing computing
  • a decision as to how to proceed in the drilling operation may be made automatically based on this analysis, or human intervention may be desirable in some situations.
  • Instructions as to how to proceed are then transmitted as signals to the controller 84 for execution at the
  • the drilling parameter can still be varied in real time in response to measurement of properties of the formation ahead of the bit, since modern communication technologies (e.g., satellite transmission, the Internet, etc.) enable transmission of signals without significant delay.
  • modern communication technologies e.g., satellite transmission, the Internet, etc.
  • FIG. 2 an enlarged scale schematic partially cross-sectional view of the drill string 16 as it is being used in a method 90 for drilling the wellbore 12 is representatively illustrated apart from the remainder of the system 10 .
  • the method 90 may be practiced with other well drilling systems in keeping with the principles of this disclosure .
  • the senor 60 is capable of measuring one or more properties of a portion 92 of the earth prior to the drill bit 14 cutting into the earth portion.
  • the sensor 60 may measure a property of an earth formation approximately 10 to 50 feet (-3 to 17 meters) ahead of the bit 14. More advanced sensors may be capable of measuring a property of an earth formation up to about 100 feet (-30 meters) ahead of the bit 14.
  • Suitable resistivity sensors which may be used for the sensor 60 are described in U.S. Patent Nos. 7557580 and 7427863.
  • a suitable sensor capable of being used to measure resistivity of an earth formation ahead of a drill bit is described in the international patent application filed on the same date herewith, having Michael S. Bittar and Burkay Donderici as inventors thereof, and entitled Deep Evaluation of Resistive Anomalies in Borehole Environments (agent file reference 09-021339).
  • such a sensor 60 is preferably interconnected in close proximity to the drill bit 14.
  • the sensor 60 may be positioned between the drill bit 14 and a fluid motor 94 (e.g., a "mud" motor) used to rotate the drill bit in response to flow of the drilling fluid 18 through the motor.
  • a fluid motor 94 e.g., a "mud" motor
  • the sensor 60 only measure resistivity of the earth portion 92.
  • the sensor 60 (or additional sensors provided in the drill string 16) could also, or alternatively, measure acoustic impedance, gamma counts due to gammas emanating from the earth portion, and/or other properties.
  • the sensor (s) 60 may be used to measure porosity of the earth portion 92, pore pressure in the earth portion, fracture pressure of the earth portion, density of the earth portion, strength of the earth portion, fluid type in the earth portion, and/or other properties. Furthermore, by measuring such properties of the earth portion 92, the presence of water, hydrocarbon fluid, salt, a fault, a formation boundary and/or another wellbore, etc. in the earth portion can be detected.
  • Measuring the property can be performed, in part, by receiving a geochemical signal, an isotope reading and/or a chromatograph reading indicative of the property of the earth portion 92. Examples of suitable techniques for doing so are described in U.S. Patent Nos. 7337660 and 7571644.
  • Fluid characterization can be used to determine: 1) the source of hydrocarbon fluid (gas and/or oil) or water, 2) whether there is up-dip hydrocarbon previously missed, 3) whether a shale is sealing or leaking, and to what extent, 4) the source of production from a fracture, 5) interconnectivity of a fractured system, 6) status of a waterflood or gasflood (such as, where the waterflood or gasflood has reached and if the wellbore 12 is about to traverse it), including early breakthrough in a region, and sweep efficiencies of the current waterflood or gasflood, 7) bypassed oil, and 8) optimization of completion methods and multi-well infill drilling campaigns.
  • the method 90 includes actually measuring one or more properties of the earth portion 92 prior to drilling into the earth portion, rather than merely predicting or estimating what such properties should be based, for
  • the method 90 enables a drilling parameter (such as choke position, operation of a flow control device, drill bit steering, drilling fluid weight, torque, rpm, bit type, weight on bit, etc.) to be varied in real time, in response to the actual measurement of at least one property of the earth portion 92 prior to drilling into that earth portion.
  • a drilling parameter such as choke position, operation of a flow control device, drill bit steering, drilling fluid weight, torque, rpm, bit type, weight on bit, etc.
  • control of drilling parameters in response to real time measurement of formation properties ahead of the drill bit 14 can be used to proactively adjust flow control devices 34, 74, 81 (e.g., to compensate for increased or decreased pore pressure in the earth portion 92, to compensate for increased or decreased fracture pressure of the earth portion, to maintain a desired bottom hole pressure, etc.), to guide a determination of whether and where to set casing (e.g., when a margin between pore and fracture pressure indicates that casing should be set, waiting until a high strength or increased pressure zone is drilled into, etc.), to avoid drilling into a water-bearing zone, to avoid drilling into an existing open or cased wellbore, to avoid or steer into salt, to avoid or steer into a fault, fracture, karst or formation boundary, to continue drilling through or to steer toward a hydrocarbon- bearing zone, etc.
  • flow control devices 34, 74, 81 e.g., to compensate for increased or decreased pore pressure in the earth portion 92, to compensate for increased or decreased fracture pressure of the earth
  • the method 90 is representatively illustrated in the situation where a formation boundary 95 exists in the earth portion 92 which is in the path of the wellbore 12 as it is being drilled.
  • One type of earth formation 96 is positioned on one side of the boundary 94, and another type of earth formation 98 is positioned on the other side of the boundary.
  • the presence of the formation boundary 95 can be detected in real time prior to drilling into the boundary, and so various pertinent decisions can be made in a timely, proactive or even preemptive manner. Furthermore, the sensor 60 can measure properties of the formations 96, 98 for use in the decision-making process.
  • the formation 98 comprises shale
  • a decision may be made to either drill into, avoid or steer away from the formation boundary 95.
  • the formation 98 comprises a water-bearing zone
  • a decision may be made to avoid or steer away from the formation boundary 95 (unless, of course it is desired to drill into a water-bearing zone, for example, in a disposal or conformance operation, etc.).
  • the formation 98 has a significantly different pore or fracture pressure, or a significantly different margin between pore and fracture pressures, as compared to the formation 96, then it may be desirable to: a) make preparations for increasing or decreasing bottom hole pressure in the wellbore 12
  • a decision may be made to delay setting casing until after drilling into the formation 98. If it is determined that the formation 98 comprises a hydrocarbon-bearing zone, then a decision may be made to steer toward and drill into the formation, delay setting casing until after drilling into the formation, etc.
  • the drill bit 14 may be replaced with the other type of drill bit prior to, or just as, the formation 98 is drilled into. For example, it may be beneficial to change between a tri-cone rock bit and a fixed cutter PDC bit, depending on the characteristics of the formations 96, 98.
  • the drill string 16 is not depicted in FIG. 4, but it will be understood that, as described above, the drill string would be used for drilling the wellbore 12 in the direction indicated by arrow 100.
  • formation anomalies (such as a fracture, karst or fault 106 in the path of the wellbore 12) can be detected before drilling into the anomalies, so that
  • the sensor 60 can detect the presence of the wellbore (for example, due to the change in density, etc.), whether the wellbore is open hole or has casing 110 therein. In response, the wellbore 12 can be steered to avoid drilling into the other wellbore 108.
  • the system 10 and method 90 enable drilling operations to be controlled based on real time measurements of formation properties ahead of the drill bit 14.
  • a drilling method 90 which includes measuring a property of a portion 92 of the earth prior to drilling a wellbore 12 into the earth portion 92; and varying a drilling parameter in real time while drilling the wellbore 12, in response to measuring the property.
  • the earth portion 92 may be at least initially in a path of a drill bit 14 being used to drill the wellbore 12.
  • Measuring the property may include measuring at least one of resistivity of the earth portion 92, acoustic
  • Measuring the property may include measuring at least one of porosity of the earth portion 92, pore pressure in the earth portion 92, fracture pressure of the earth portion 92, density of the earth portion 92, strength of the earth portion 92, and fluid type in the earth portion 92.
  • Measuring the property may include detecting the presence of at least one of water, hydrocarbon fluid, salt, a fault 106, a formation boundary 95 and another wellbore 108.
  • Varying the drilling parameter may include varying pressure in the wellbore 12. Varying pressure in the wellbore 12 may include adjusting a flow control device 34, 74, 76, 78, 81.
  • the flow control device 34 may variably restrict flow through a return line 30 for discharging drilling fluid 18 from an annulus 20 formed between the wellbore 12 and a drill string 16.
  • the flow control device 81 may variably restrict flow through a standpipe line 26 for injecting drilling fluid 18 into a drill string 16 used to drill the wellbore 12.
  • the flow control device 74 may variably restrict flow between a standpipe line 26 for injecting drilling fluid 18 into a drill string 16 used to drill the wellbore 12 and a return line 30 for discharging drilling fluid 18 from an annulus 20 formed between the wellbore 12 and the drill string 16.
  • Varying pressure in the wellbore 12 may be performed in response to at least one of: determining that the earth portion 92 comprises shale, determining that a pore pressure of the earth portion 92 is greater than that of an already drilled portion, determining that the pore pressure of the earth portion 92 is less than that of the already drilled portion, determining that a fracture pressure of the earth portion 92 is greater than that of the already drilled portion, determining that the fracture pressure of the earth portion 92 is less than that of the already drilled portion, and determining that the earth portion 92 comprises a formation boundary 95.
  • Varying the drilling parameter may include adjusting a flow control device 34, 74, 81, thereby maintaining a desired pressure in the wellbore 12.
  • Varying the drilling parameter may include steering the wellbore 12 and thereby continuing to drill in a
  • parameter may include steering the wellbore 12 toward the hydrocarbon-bearing zone 102. Varying the drilling
  • parameter may include steering the wellbore 12 toward or away from a water-bearing zone 104.
  • Varying the drilling parameter may include steering the wellbore 12 toward or away from a fault 106, toward or away from a formation boundary 95, and/or toward or away from another wellbore 108.
  • Varying the drilling parameter may include changing a drill bit 14 on a drill string 16 used to drill the wellbore 12.
  • Measuring the property may be performed utilizing a resistivity sensor 60 positioned between a fluid motor 94 and a drill bit 14 in a drill string 16 used to drill the wellbore 12.
  • the method 90 may also include transmitting a signal representative of the measured property to a remote location for analysis prior to varying the drilling parameter.
  • pressure in the wellbore 12 may be greater than, equal to, or less than pore pressure in an earth formation exposed to the wellbore 12.
  • Measuring the property may include receiving at least one of a geochemical signal, an isotope reading and a chromatograph reading indicative of the property of the earth portion 92.
  • Measuring the property may include characterizing a fluid in the earth portion. Measuring the property may include detecting the presence of at least one of a fracture and a karst in the earth portion 92.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Earth Drilling (AREA)

Abstract

La présente invention concerne un procédé de forage de puits qui utilise une réponse en temps réel avant des mesures de foret. Un procédé de forage de puits consiste à mesurer une propriété d'une partie du sol avant de forer un puits dans la partie du sol ; et à varier un paramètre de forage en temps réel tout en forant le puits, en réponse à la mesure de la propriété.
PCT/US2009/059541 2009-10-05 2009-10-05 Procédé de forage de puits utilisant une réponse en temps réel avant des mesures de foret WO2011043763A1 (fr)

Priority Applications (5)

Application Number Priority Date Filing Date Title
PCT/US2009/059541 WO2011043763A1 (fr) 2009-10-05 2009-10-05 Procédé de forage de puits utilisant une réponse en temps réel avant des mesures de foret
EP10822500A EP2486429A1 (fr) 2009-10-05 2010-10-05 Procédé de forage de puits utilisant une réponse en temps réel à des mesures en avant du trépan
PCT/US2010/051384 WO2011044069A1 (fr) 2009-10-05 2010-10-05 Procédé de forage de puits utilisant une réponse en temps réel à des mesures en avant du trépan
US13/391,833 US20120186873A1 (en) 2009-10-05 2010-10-05 Well drilling method utilizing real time response to ahead of bit measurements
AU2010303666A AU2010303666A1 (en) 2009-10-05 2010-10-05 Well drilling method utilizing real time response to ahead of bit measurements

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2009/059541 WO2011043763A1 (fr) 2009-10-05 2009-10-05 Procédé de forage de puits utilisant une réponse en temps réel avant des mesures de foret

Related Child Applications (1)

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US13/391,833 Continuation-In-Part US20120186873A1 (en) 2009-10-05 2010-10-05 Well drilling method utilizing real time response to ahead of bit measurements

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WO2011043763A1 true WO2011043763A1 (fr) 2011-04-14

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PCT/US2010/051384 WO2011044069A1 (fr) 2009-10-05 2010-10-05 Procédé de forage de puits utilisant une réponse en temps réel à des mesures en avant du trépan

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EP2486230B1 (fr) 2009-10-05 2018-09-05 Halliburton Energy Services, Inc. Déterminations géomécaniques intégrées et régulation de pression de forage
WO2011043851A1 (fr) 2009-10-05 2011-04-14 Halliburton Energy Services, Inc. Évaluation approfondie d'anomalies résistantes dans des environnements de trou de forage
US8860416B2 (en) 2009-10-05 2014-10-14 Halliburton Energy Services, Inc. Downhole sensing in borehole environments
US8854044B2 (en) 2011-11-09 2014-10-07 Haliburton Energy Services, Inc. Instrumented core barrels and methods of monitoring a core while the core is being cut

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