+

WO2012166137A1 - Forage à pression optimisée à train de tiges de forage à tubulure continue - Google Patents

Forage à pression optimisée à train de tiges de forage à tubulure continue Download PDF

Info

Publication number
WO2012166137A1
WO2012166137A1 PCT/US2011/038838 US2011038838W WO2012166137A1 WO 2012166137 A1 WO2012166137 A1 WO 2012166137A1 US 2011038838 W US2011038838 W US 2011038838W WO 2012166137 A1 WO2012166137 A1 WO 2012166137A1
Authority
WO
WIPO (PCT)
Prior art keywords
wellbore
pressure
drill string
fluid
sensing
Prior art date
Application number
PCT/US2011/038838
Other languages
English (en)
Inventor
John L. Maida Jr.
Neal G. Skinner
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 MYPI2013004098A priority Critical patent/MY164665A/en
Priority to PCT/US2011/038838 priority patent/WO2012166137A1/fr
Priority to CA2837859A priority patent/CA2837859C/fr
Priority to EP11866637.9A priority patent/EP2715035A4/fr
Priority to RU2013158132/03A priority patent/RU2565299C2/ru
Priority to AU2011369403A priority patent/AU2011369403B2/en
Priority to BR112013030718A priority patent/BR112013030718A2/pt
Priority to CN201180071386.XA priority patent/CN103635655B/zh
Priority to US13/470,742 priority patent/US8448720B2/en
Publication of WO2012166137A1 publication Critical patent/WO2012166137A1/fr
Priority to US13/775,934 priority patent/US8573325B2/en

Links

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
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/08—Wipers; Oil savers
    • E21B33/085—Rotatable packing means, e.g. rotating blow-out preventers
    • 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
    • E21B47/13—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 by electromagnetic energy, e.g. radio frequency
    • E21B47/135—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 by electromagnetic energy, e.g. radio frequency using light waves, e.g. infrared or ultraviolet waves
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/42—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators in one well and receivers elsewhere or vice versa

Definitions

  • the present disclosure relates generally to equipment utilized and operations performed in conjunction with drilling a well and, in an embodiment described herein, more particularly provides for optimized pressure drilling with a continuous tubing drill string.
  • sensors at the surface and in a bottom hole assembly of a drill string can be used to detect various parameters affecting the drilling operation.
  • sensors do not measure parameters along the drill string, and are of limited usefulness in detecting an influx of fluid into a wellbore, or in
  • FIG. 1 is a representative partially cross-sectional view of a well system and associated method which can embody principles of this disclosure.
  • FIG. 2 is a representative block diagram of a process control system which may be used with the well system and method of FIG. 1.
  • FIG. 3 is a representative view of another
  • FIG. 4 is an enlarged scale representative partially cross-sectional view of a portion of the well system.
  • FIG. 5 is a representative graph of temperature versus depth along the wellbore, the graph containing an indication of fluid loss from the wellbore.
  • FIG. 6 is a representative graph of temperature versus depth along the wellbore, the graph containing an indication of fluid influx into the wellbore.
  • FIG. 7 is a representative flowchart for a method of detecting an influx and adjusting a choke in response, which method can embody principles of this disclosure.
  • FIG. 8 is a representative flowchart for a method of detecting a fluid loss and adjusting a choke in response, which method can embody principles of this disclosure.
  • FIG. 1 Representatively illustrated in FIG. 1 is a well system 10 and associated method which can embody principles of this disclosure.
  • a wellbore 12 is drilled by rotating a drill bit 14 on an end of a tubular drill string 16.
  • Drilling fluid commonly known as mud
  • a non-return valve 21 prevents flow of the drilling fluid 18 upward through the drill string 16.
  • bottom hole pressure is very important in managed pressure and underbalanced drilling, and in other types of optimized pressure drilling operations.
  • the bottom hole pressure is optimized to prevent excessive loss of fluid into an earth formation 64 surrounding the wellbore 12, undesired fracturing of the formation,
  • Nitrogen or another gas, or another lighter weight fluid may be added to the drilling fluid 18 for pressure control. This technique is especially useful, for example, in underbalanced drilling operations, or in segregated density (such as dual gradient) managed pressure drilling.
  • RCD rotating control device 22
  • the drill string 16 would extend upwardly through the RCD 22 for connection to, for example, a standpipe line 26 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 a fluid return line 30 to a choke manifold 32, which includes redundant chokes 34.
  • Backpressure is applied to the annulus 20 by variably restricting flow of the fluid 18 through the operative one(s) of the redundant chokes 34.
  • bottom hole pressure can be conveniently regulated by varying the backpressure applied to the annulus 20 by varying the restriction to flow through the choke(s) 34.
  • a hydraulics model can be used, as described more fully below, to determine a pressure applied to the annulus 20 at or near the surface, which pressure 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 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 fluid return line 30 upstream of the choke manifold 32 .
  • Another pressure sensor 44 senses pressure in the 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 , 66 .
  • the system 10 could include only one of the flowmeters 62 , 66 . However, input from the sensors is useful to the
  • the drill string 16 may include its own sensors 60 , for example, to directly measure bottom hole pressure.
  • sensors 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) sensor 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, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.) and/or other measurements.
  • Various forms of telemetry may be used to transmit the downhole sensor measurements to the surface.
  • the drill string 16 could be provided with conductors, optical waveguides, etc., for transmission of data and/or commands between the sensors 60 and the process control system 74 described below (see FIG. 2).
  • 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.
  • the output of the rig mud pump 68 could be determined by counting pump strokes, instead of by using the 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 86 (not shown in FIG. 1, see FIG. 3) to the standpipe line 26.
  • the fluid 18 then circulates downward through the drill string 16, upward through the annulus 20, through the mud return line 30, through the choke manifold 32, and then via the separator 48 and shaker 50 to the mud pit 52 for
  • 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 lack of circulation can occur whenever 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.
  • a backpressure pump 70 can be used to supply a flow of fluid to the return line 30 upstream of the choke manifold 32 by pumping fluid into the annulus 20 or another location upstream of the choke manifold.
  • the pump 70 is connected to the annulus 20 via the BOP stack 42, but in other examples the pump 70 could be connected to the return line 30, or to the choke manifold 32.
  • fluid could be diverted from the standpipe manifold (or otherwise from the rig pump 68) to the return line 30 when needed, as described in
  • a flowmeter 72 can be used to measure the output of the pump.
  • the choke 34 and backpressure pump 70 are examples of pressure control devices which can be used to control pressure in the annulus 20 near the surface. Other types of pressure control devices (such as those described in
  • FIG. 2 a block diagram of one example of a process control system 74 is
  • process control system 74 could include other numbers, types, combinations, etc., of elements, and any of the elements could be positioned at different locations or integrated with another element, in keeping with the scope of this disclosure .
  • the process control system 74 includes a data acquisition and control interface 118, a hydraulics model 120, a predictive device 122, a data validator 124 and a controller 126. These elements may be similar to those described in International Application Serial No. PCT/USlO/56433 filed on 12 November 2010.
  • the hydraulics model 120 is used to determine a desired pressure in the annulus 20 to thereby achieve a desired pressure at a certain location in the wellbore 12.
  • the hydraulics model 120 uses data such as wellbore depth, drill string rpm, running speed, mud type, etc., models the wellbore 12, the drill string 16, flow of the fluid through the drill string and annulus 20 (including equivalent circulating density due to such flow), etc.
  • the data acquisition and control interface 118 receives data from the various sensors 36 , 38 , 40 , 44 , 46 , 54 , 56 , 58 , 60 , 62 , 66 , 67 , 72 , together with rig and downhole data, and relays this data to the hydraulics model 120 and the data validator 124 .
  • the interface 118 relays the desired annulus pressure from the hydraulics model 120 to the data validator 124 .
  • the predictive device 122 can be included in this example to determine, based on past data, what sensor data should currently be received and what the desired annulus pressure should be.
  • the predictive device 122 could comprise a neural network, a genetic algorithm, fuzzy logic, etc., or any combination of predictive elements, to produce
  • the data validator 124 uses these predictions to determine whether any particular sensor data is valid, whether the desired annulus pressure output by the
  • hydraulics model 120 is appropriate, etc. If it is
  • the data validator 124 transmits the desired annulus pressure to the controller 126 (such as a
  • programmable logic controller which may include a
  • PID controller which controls operation of the choke 34 , the pump 70 and the various flow control devices 128 (such as valves, etc.).
  • the choke 34 , pump 70 and flow control devices 128 can be automatically controlled to achieve and maintain the desired pressure in the annulus 20 .
  • Actual pressure in the annulus 20 is typically measured at or near the wellhead 24 (for example, using sensors 36 , 38 , 40 ) , which may be at a land or subsea location.
  • the flow control device 76 can be interconnected between the rig pump 68 and the standpipe manifold 86 using, for example, quick connectors 84 (such as, hammer unions, etc.). This will allow the flow control device 76 to be conveniently adapted for interconnection in various rigs' pump lines.
  • a specially adapted fully automated flow control device 76 (e.g., as one of the flow control devices 128 controlled automatically by the controller 126) can be used for
  • the flow control device 76 along with one or more additional flow control devices 78, 80, 82 can be used to divert flow of the fluid 18 from the rig pump(s) 68 to the choke manifold 32 via a bypass line 75.
  • the drill string 16 comprises coiled tubing or otherwise continuous tubing, which has at least one optical waveguide 88 (such as, an optical fiber, ribbon, etc.) extending along its length.
  • optical waveguide 88 such as, an optical fiber, ribbon, etc.
  • the waveguide 88 is depicted as extending through an interior longitudinal flow passage 90 of the drill string 16, but in other examples the waveguide may extend in a sidewall of the drill string, exterior to the drill string, etc.
  • the waveguide 88 may be in the form of a loop that starts at the top of the coiled tubing, extends to the bottom, turns around and returns to the surface for improved temperature measurement performance.
  • Multiple optical waveguides 88 could be provided, along with other types of lines (e.g., electrical lines and/or hydraulic lines, etc.). The various lines may be
  • the optical waveguide 88 may be installed in a tube or control line with the drill string 16.
  • both single mode and multimode optical waveguides 88 are
  • the drill string 16 is preferably continuous (e.g., not jointed or segmented) at least from the wellhead 24 to near a bottom hole assembly (e.g., including but not limited to the sensors 60, non-return valve 21, drill bit 14, a mud motor 92 (see FIG. 1) which rotates the drill bit in
  • a bottom hole assembly e.g., including but not limited to the sensors 60, non-return valve 21, drill bit 14, a mud motor 92 (see FIG. 1) which rotates the drill bit in
  • the waveguide 88 may be installed in the drill string 16 before or after the drill string is conveyed into the wellbore 12.
  • FIG. 4 depicts a situation in which the fluid 18 is lost to the formation 64. That is, the fluid 18 flows from the wellbore 12 into the formation 64.
  • This situation can occur, for example, when the
  • pressure in the wellbore 12 is greater than the fracture pressure of the formation 64.
  • Such a situation is generally to be avoided, but can be used to advantage (e.g., in order to conveniently determine the fracture pressure, etc.), as described more fully below.
  • FIG. 4 depicts another situation in which formation fluid 94 flows into the wellbore 12 from the formation 64. This situation can occur, for example, when the pressure in the wellbore 12 is less than the pore pressure of the formation 64.
  • underbalanced drilling operations e.g., with controlled influx of the formation fluid 94 into the wellbore 12 while drilling
  • other types of drilling operations e.g., managed pressure drilling, conventional overbalanced drilling, etc.
  • influx of the formation fluid 94 into the wellbore 12 can be used to conveniently determine the pore pressure of the formation 64.
  • FIG. 5 a representative graph 96 of temperature versus depth is depicted for the section of the wellbore 12 illustrated in FIG. 4, and for the fluid 18 loss situation shown on the left-hand side of FIG. 4. Note that a
  • temperature decrease 98 is detected at the location where the fluid 18 enters the formation 64.
  • the temperature decrease 98 is due to the fluid 18 locally cooling the formation 64 at the location where the fluid enters the formation. Such a temperature decrease 98 anomaly can be used to detect where and when a fluid 18 loss event occurs, and can be used to determine when the fracture pressure of the formation 64 has been reached.
  • FIG. 6 a representative graph 100 of temperature versus depth is depicted for the section of the wellbore 12 illustrated in FIG. 4, and for the fluid 94 influx situation shown on the right-hand side of FIG. 4. Note that a
  • the temperature increase 102 is due to the fluid 94 locally heating the wellbore 12 at the location where the fluid enters the wellbore.
  • Such a temperature increase 102 anomaly can be used to detect where and when a fluid 94 influx event occurs, and can be used to determine when the pressure in the wellbore becomes less than the pore pressure of the formation 64.
  • temperature is measured with the optical waveguide 88 using the well-known technique of distributed temperature sensing (DTS).
  • DTS is a technology that can be used to measure temperature distribution along the optical waveguide 88.
  • a pulsed laser source can be used to send a pulse of light through the optical waveguide 88, and properties of returning light can be recorded.
  • backscatter comprises absorption and retransmission of light energy.
  • the backscattered light includes different spectral components, e.g., Rayleigh, Brillouin, and Raman bands.
  • the Raman band can be used to obtain temperature information along the fiber.
  • the Raman backscatter has two components, Stokes and Anti-Stokes, the former being weakly dependent on
  • the relative intensity between the Stokes and Anti-Stokes components is a function of temperature at which the backscattering occurs.
  • a DTS trace or profile (such as the graphs 96, 100 of FIGS. 5 & 6) is a set of temperature measurements or sample points, equally spaced along the waveguide 88 length.
  • Brillouin backscatter wavelength is also temperature dependent and, thus, can be used for DTS.
  • the DTS Downlink
  • Brillouin backscatter is also dependent on localized strain in the waveguide 88, and so for temperature measurements, the strain component can be eliminated (e.g., by ensuring that the waveguide is not subjected to strain), canceled out, etc.
  • the optical waveguide 88 is used for DTS monitoring.
  • DAS distributed acoustic sensing
  • DSS distributed strain sensing
  • DVD distributed vibration sensing
  • Raman backscatter sensing is typically used for DTS monitoring, but Brillouin backscatter sensing can also be used, if desired. Brillouin or Rayleigh backscatter sensing may be used for DAS, DSS or DVS
  • Brillouin backscatter gain or coherent Rayleigh backscatter being sensed.
  • Interferometric optical sensing may also (or alternatively) be used, as well.
  • DAS may be used to sense the acoustic signal produced when the fluid 94 flows into the wellbore 12 from the formation 64 (e.g., a fluid influx), or a decreased acoustic amplitude due to the fluid 18 flowing from the wellbore into the formation (e.g., a fluid loss).
  • Other characteristics of the drilling operation such as drill string 16 vibration, stick-slip, whirl, strain, etc. may also, or alternatively, be measured using the optical waveguide 88.
  • DAS may be used to detect an acoustic signature of gas entering the wellbore 12 from the formation 64, and/or of gas flowing through the annulus 20.
  • the DAS may be used to detect an acoustic signature of gas entering the wellbore 12 from the formation 64, and/or of gas flowing through the annulus 20.
  • waveguide 88 will indicate less damped acoustic ringing in portions of the drill string 16 exposed to gas in the wellbore 12, so optical equipment connected to the waveguide can be used to detect distributed acoustic resonance in the drill string for this purpose.
  • DAS can be used to detect acoustic waves produced by another drill string (not shown) in another close wellbore (not shown). While the other drill string drills the other wellbore, the waveguide 88 detects the acoustic waves produced by the other drill string, so that the location of the other wellbore relative to the wellbore 12 can be readily determined, in order to guide the wellbores to intersect or avoid each other. DAS can be used to detect other events in or out of the wellbore 12 which can produce an acoustic signal. For example, a washout occurring in the wellbore 12 could be detected by the waveguide 88. As another example, a seismic source could be activated at the surface, in another
  • point measurement of properties can be made using one or more sensors 104.
  • the sensors 104 could include a pressure sensor, a chemical ion or pH sensor, an ionizing radiation sensor, a magnetic field sensor, etc.
  • the sensors 104 could be optical or other types of sensors, and may or not be connected to or part of the waveguide 88.
  • the sensors 104 are not necessarily optically coupled to the waveguide 88. Instead, the sensors 104 could communicate acoustically with the waveguide 88. In this example, the sensors 104 could emit acoustic signals on which their measurements are modulated (e.g., using
  • the acoustic signals could be received by the waveguide 88 and transmitted optically (as backscatter variations) to a remote location (such as, the earth's surface, a drilling rig, a sea floor wellhead, etc.).
  • a remote location such as, the earth's surface, a drilling rig, a sea floor wellhead, etc.
  • a line 106 comprises an electrical conductor which serves as an antenna to induce a magnetic field in the formation 64. Variations in the magnetic field are indicative of resistivity changes in the formation 64.
  • the well-known Faraday effect in the waveguide 88 can be detected as an indication of the magnetic field changes in the formation 64.
  • the drill string 16 could be made of a composite or other non-magnetic material, so that it does not interfere with propagating the magnetic field into the formation 64, and with detecting the magnetic field variations in the formation.
  • logging can be performed with the waveguide 88 while the drilling operation progresses.
  • the waveguide 88 can, for example, detect gamma radiation from the formation 64. In this manner, an operator can know when particular subterranean strata are penetrated, the strata adjacent the drill string 16 can be correlated to expected subterranean strata, etc.
  • the drill string 16 would be performed with the waveguide 88 while the drilling operation progresses.
  • the waveguide 88 can, for example, detect gamma radiation from the formation 64. In this manner, an operator can know when particular subterranean strata are penetrated, the strata adjacent the drill string 16 can be correlated to expected subterranean strata, etc.
  • the drill string 16 would
  • Ionizing radiation can be detected along the waveguide 88 by providing a phosphorescent or fluorescent cladding on the waveguide.
  • Different strata can have different spectral absorbing signatures, allowing for identification and verification of the strata based on the signatures.
  • a method 108 which may be used with the well system 10 configuration of FIG. 4 is representatively illustrated in flowchart form.
  • the method 108 could be practiced with other well systems, in keeping with the principles of this disclosure.
  • an influx of formation fluid 94 is detected as an indication of the pore pressure of the formation 64.
  • the formation fluid 94 is induced by the pressure differential to flow toward and into the wellbore .
  • the point at which an influx starts is the point at which pressure in the wellbore 12 becomes less than the pore pressure of the formation 64.
  • Pressure in the wellbore 12 can be readily measured (e.g., using sensors 60, 104, etc.), and pressure in the annulus 20 near the surface can be conveniently measured (e.g., using sensors 38, 40, etc.), when such an influx occurs.
  • the pressure in the wellbore 12 at the location of the influx can include friction pressure due to flow of the fluid 18 (also known as equivalent circulating density), so this pressure (if any) is preferably taken into account when determining the actual pressure in the wellbore at the location of the influx. It is not necessary, however, for the fluid 18 to be circulating through the drill string 16 and annulus 20 while the method 108 is performed.
  • the pump 70 (see FIG. 1) and/or rig pump 68 (see FIG. 3) could be used to supply flow through the choke 34 during the method 108, without the fluid 18 circulating through the drill string 16 and annulus 20.
  • step 110 of the method 108 the choke 34 is adjusted to gradually decrease pressure in the wellbore 12.
  • pressure upstream of the choke is reduced and, thus, pressure applied to the annulus 20 near the surface is reduced.
  • step 112 an influx is detected. For example, using
  • an acoustic or thermal indication of the influx can be readily detected (e.g., as depicted in FIG. 6).
  • the pressure in the wellbore 12 at the location of the influx can be measured (e.g., using sensors 60, 104, etc.) and/or pressure in the annulus 20 near the surface can be measured (e.g., using sensors 38, 40, etc.) at the time of the influx. These pressure measurements will indicate the pore pressure of the formation 64 at the location of the influx .
  • the choke 34 is adjusted as needed for the particular drilling operation.
  • the choke 34 may be adjusted so that pressure in the wellbore 12 is somewhat greater than pore pressure of the formation 64 (which can be subsequently verified by a lack of influx as detected by the waveguide 88 after adjustment of the choke).
  • the choke 34 may be adjusted so that a controlled amount of influx is permitted during drilling (which can be
  • FIG. 8 another method 130 which may be used with the well system 10 configuration of FIG. 4 is representatively illustrated in flowchart form. Of course, the method 130 could be practiced with other well systems, in keeping with the principles of this disclosure.
  • a loss of fluid 18 to the formation 64 is detected as an indication of the fracture pressure of the formation.
  • the point at which a loss of fluid 18 begins is the point at which pressure in the wellbore 12 becomes more than the fracture pressure of the formation 64.
  • Pressure in the wellbore 12 can be readily measured (e.g., using sensors 60, 104, etc.), and pressure in the annulus 20 near the surface can be conveniently measured (e.g., using sensors 38, 40, etc.) at the time of the loss of fluid 18.
  • pressure in the wellbore 12 at the location of the fluid loss can include friction pressure due to flow of the fluid 18 (also known as equivalent
  • the pump 70 (see FIG. 1) and/or rig pump 68 (see FIG. 3) could be used to supply flow through the choke 34 during the method 130, without the fluid 18 circulating through the drill string 16 and annulus 20.
  • step 132 of the method 130 the choke 34 is adjusted to gradually increase pressure in the wellbore 12.
  • pressure upstream of the choke is increased and, thus, pressure applied to the annulus 20 near the surface is increased.
  • a loss of fluid 18 is detected.
  • an acoustic or thermal indication of the loss of fluid 18 can be readily detected (e.g., as depicted in FIG. 5).
  • the pressure in the wellbore 12 at the location of the fluid loss can be measured (e.g., using sensors 60, 104, etc.) and/or pressure in the annulus 20 near the surface can be measured (e.g., using sensors 38, 40, etc.) at the time of the loss. These pressure measurements will indicate the fracture pressure of the formation 64 at the location of the fluid loss.
  • the choke 34 is adjusted as needed for the particular drilling operation.
  • the choke 34 may be adjusted so that pressure in the wellbore 12 is somewhat greater than pore pressure of the formation 64 (which can be subsequently verified by a lack of influx as detected by the waveguide 88 after adjustment of the choke) and less than fracture pressure of the formation.
  • the choke 34 may be adjusted so that a controlled amount of influx is permitted during drilling (which can be
  • otherwise continuous tubing drill string 16 includes the optical waveguide 88 which provides for distributed and/or point sensing of various parameters.
  • the use of a continuous tubing drill string 16 with the optical waveguide 88 therein provides for convenient tripping of the drill string and waveguide into and out of the wellbore 12, with no need for attaching the waveguide to, or detaching the waveguide from, an exterior of the drill string as sections of the drill string are connected to or disconnected from the drill string .
  • the above disclosure describes a method of drilling a wellbore 12. The method can include drilling the wellbore 12 with a continuous tubing drill string 16, and sensing at least one parameter with an optical waveguide 88 in the drill string 16.
  • the drill string 16 may be continuous at least from a surface location to a bottom hole assembly of the drill string 16.
  • Sensing at least one parameter can comprise sensing the parameter as distributed along the drill string 16.
  • DAS Distributed acoustic sensing
  • DTS distributed vibration sensing
  • DFS distributed strain sensing
  • the sensed parameter may be selected from the group comprising pressure, temperature, chemical ion, ionizing radiation, pH, magnetic field and gamma radiation.
  • any other parameter ( s ) and any number or
  • the method 108 can include adjusting a choke 34, thereby inducing an influx of fluid 94 into the wellbore 12, and sensing at least one parameter may include detecting the influx.
  • the method 108 may also include measuring pressure in the wellbore 12 when detecting the influx, thereby correlating the pressure in the wellbore 12 to pore pressure in a formation 64 intersected by the wellbore 12.
  • the method 108 may also include adjusting the choke 34 in response to detecting the influx.
  • the method 130 can include adjusting a choke 34, thereby inducing a loss of fluid 18 from the wellbore 12, and sensing at least one parameter may include detecting the loss of fluid 18.
  • the method 130 may also include measuring pressure in the wellbore 12 when detecting the loss of fluid 18, thereby correlating the pressure in the wellbore 12 to fracture pressure in a formation 64 intersected by the wellbore 12.
  • the method 130 may also include adjusting the choke 34 in response to detecting the loss of fluid 18.
  • the optical waveguide 88 may be positioned in an interior flow passage 90 of the drill string 16.
  • the well system 10 may include a continuous tubing drill string 16, and an optical waveguide 88 in the drill string 16.
  • the optical waveguide 88 may sense at least one

Landscapes

  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Remote Sensing (AREA)
  • Mechanical Engineering (AREA)
  • Electromagnetism (AREA)
  • Geophysics (AREA)
  • Earth Drilling (AREA)
  • Geophysics And Detection Of Objects (AREA)
  • Investigating Or Analysing Materials By Optical Means (AREA)
  • Measuring Fluid Pressure (AREA)

Abstract

L'invention porte sur un procédé de forage d'un puits de forage, lequel procédé peut mettre en œuvre le forage du puits de forage à l'aide d'un train de tiges de forage à tubulure continue, et la détection d'au moins un paramètre à l'aide d'un guide d'ondes optique dans le train de tiges de forage. Un système de puits peut comprendre un train de tiges de forage à tubulure continue, et un guide d'ondes optique dans le train de tiges de forage. Le guide d'ondes optique peut détecter au moins un paramètre réparti le long du train de tiges de forage.
PCT/US2011/038838 2011-06-02 2011-06-02 Forage à pression optimisée à train de tiges de forage à tubulure continue WO2012166137A1 (fr)

Priority Applications (10)

Application Number Priority Date Filing Date Title
MYPI2013004098A MY164665A (en) 2011-06-02 2011-06-02 Optimized pressure drilling with continuous tubing drill string
PCT/US2011/038838 WO2012166137A1 (fr) 2011-06-02 2011-06-02 Forage à pression optimisée à train de tiges de forage à tubulure continue
CA2837859A CA2837859C (fr) 2011-06-02 2011-06-02 Forage a pression optimisee a train de tiges de forage a tubulure continue
EP11866637.9A EP2715035A4 (fr) 2011-06-02 2011-06-02 Forage à pression optimisée à train de tiges de forage à tubulure continue
RU2013158132/03A RU2565299C2 (ru) 2011-06-02 2011-06-02 Бурение с оптимизацией давления непрерывной бурильной колонной насосно-компрессорных труб
AU2011369403A AU2011369403B2 (en) 2011-06-02 2011-06-02 Optimized pressure drilling with continuous tubing drill string
BR112013030718A BR112013030718A2 (pt) 2011-06-02 2011-06-02 método para perfurar um furo de poço, e, sistema de poço
CN201180071386.XA CN103635655B (zh) 2011-06-02 2011-06-02 一种钻探井筒的方法和井系统
US13/470,742 US8448720B2 (en) 2011-06-02 2012-05-14 Optimized pressure drilling with continuous tubing drill string
US13/775,934 US8573325B2 (en) 2011-06-02 2013-02-25 Optimized pressure drilling with continuous tubing drill string

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2011/038838 WO2012166137A1 (fr) 2011-06-02 2011-06-02 Forage à pression optimisée à train de tiges de forage à tubulure continue

Publications (1)

Publication Number Publication Date
WO2012166137A1 true WO2012166137A1 (fr) 2012-12-06

Family

ID=47259675

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2011/038838 WO2012166137A1 (fr) 2011-06-02 2011-06-02 Forage à pression optimisée à train de tiges de forage à tubulure continue

Country Status (8)

Country Link
EP (1) EP2715035A4 (fr)
CN (1) CN103635655B (fr)
AU (1) AU2011369403B2 (fr)
BR (1) BR112013030718A2 (fr)
CA (1) CA2837859C (fr)
MY (1) MY164665A (fr)
RU (1) RU2565299C2 (fr)
WO (1) WO2012166137A1 (fr)

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2526255A (en) * 2014-04-15 2015-11-25 Managed Pressure Operations Drilling system and method of operating a drilling system
US10718204B2 (en) 2015-06-15 2020-07-21 Halliburton Energy Services, Inc. Identifying fluid level for down hole pressure control with depth derivatives of temperature
GB2535086B (en) * 2013-12-17 2020-11-18 Halliburton Energy Services Inc Distributed acoustic sensing for passive ranging

Families Citing this family (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
BR112014000553B8 (pt) * 2011-07-12 2021-02-17 Halliburton Energy Services Inc método de testagem de uma formação de solo
US8783381B2 (en) 2011-07-12 2014-07-22 Halliburton Energy Services, Inc. Formation testing in managed pressure drilling
US10538986B2 (en) * 2017-01-16 2020-01-21 Ensco International Incorporated Subsea pressure reduction manifold
RU2640844C1 (ru) * 2017-03-23 2018-01-12 Федеральное государственное бюджетное учреждение науки Институт Земной коры Сибирского отделения Российской академии наук Способ спуска обсадной колонны в горизонтальном стволе большой протяженности
RU2649204C1 (ru) * 2017-04-13 2018-03-30 Федеральное государственное бюджетное образовательное учреждение высшего образования "Кубанский государственный технологический университет" (ФГБОУ ВО "КубГТУ") Способ вскрытия продуктивного пласта на управляемой депрессии
CN109375266B (zh) * 2018-12-18 2024-02-02 清华大学 一种采用斜长分布式光纤的地下水封洞库安全监测系统

Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3905010A (en) * 1973-10-16 1975-09-09 Basic Sciences Inc Well bottom hole status system
US20040065477A1 (en) * 2002-10-04 2004-04-08 Halliburton Energy Services, Inc. Well control using pressure while drilling measurements
US20040129418A1 (en) * 2002-08-15 2004-07-08 Schlumberger Technology Corporation Use of distributed temperature sensors during wellbore treatments
US20060165344A1 (en) 2005-01-25 2006-07-27 Vetco Gray Inc. Fiber optic sensor and sensing system for hydrocarbon flow
US20070221407A1 (en) * 2002-11-05 2007-09-27 Bostick F X Iii Permanent downhole deployment of optical sensors
US7409858B2 (en) 2005-11-21 2008-08-12 Shell Oil Company Method for monitoring fluid properties

Family Cites Families (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
RU2199006C2 (ru) * 2001-03-30 2003-02-20 Общество с ограниченной ответственностью "Кубаньгазпром" Устройство бурения наклонных и горизонтальных скважин
US6997256B2 (en) * 2002-12-17 2006-02-14 Sensor Highway Limited Use of fiber optics in deviated flows
CN2727395Y (zh) * 2004-05-28 2005-09-21 徐凌堂 一种高温高压光波导测井系统
US7617873B2 (en) * 2004-05-28 2009-11-17 Schlumberger Technology Corporation System and methods using fiber optics in coiled tubing
US7597142B2 (en) * 2006-12-18 2009-10-06 Schlumberger Technology Corporation System and method for sensing a parameter in a wellbore
CN101975057A (zh) * 2010-10-28 2011-02-16 华东理工大学 一种适用于深井及超深井的实时控制钻采系统

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3905010A (en) * 1973-10-16 1975-09-09 Basic Sciences Inc Well bottom hole status system
US20040129418A1 (en) * 2002-08-15 2004-07-08 Schlumberger Technology Corporation Use of distributed temperature sensors during wellbore treatments
US20040065477A1 (en) * 2002-10-04 2004-04-08 Halliburton Energy Services, Inc. Well control using pressure while drilling measurements
US20070221407A1 (en) * 2002-11-05 2007-09-27 Bostick F X Iii Permanent downhole deployment of optical sensors
US20060165344A1 (en) 2005-01-25 2006-07-27 Vetco Gray Inc. Fiber optic sensor and sensing system for hydrocarbon flow
US7409858B2 (en) 2005-11-21 2008-08-12 Shell Oil Company Method for monitoring fluid properties

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
See also references of EP2715035A4

Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2535086B (en) * 2013-12-17 2020-11-18 Halliburton Energy Services Inc Distributed acoustic sensing for passive ranging
GB2526255A (en) * 2014-04-15 2015-11-25 Managed Pressure Operations Drilling system and method of operating a drilling system
US10443329B2 (en) 2014-04-15 2019-10-15 Managed Pressure Operations Pte. Ltd. Drilling system and method of operating a drilling system
GB2526255B (en) * 2014-04-15 2021-04-14 Managed Pressure Operations Drilling system and method of operating a drilling system
NO348017B1 (en) * 2014-04-15 2024-06-24 Grant Prideco Inc Drilling system and method of operating a drilling system
US10718204B2 (en) 2015-06-15 2020-07-21 Halliburton Energy Services, Inc. Identifying fluid level for down hole pressure control with depth derivatives of temperature

Also Published As

Publication number Publication date
BR112013030718A2 (pt) 2016-12-06
AU2011369403B2 (en) 2014-03-13
RU2565299C2 (ru) 2015-10-20
EP2715035A4 (fr) 2014-11-26
CN103635655B (zh) 2016-03-30
AU2011369403A1 (en) 2013-11-14
CA2837859A1 (fr) 2012-12-06
MY164665A (en) 2018-01-30
EP2715035A1 (fr) 2014-04-09
RU2013158132A (ru) 2015-07-20
CA2837859C (fr) 2016-05-24
CN103635655A (zh) 2014-03-12

Similar Documents

Publication Publication Date Title
US8448720B2 (en) Optimized pressure drilling with continuous tubing drill string
CA2837859C (fr) Forage a pression optimisee a train de tiges de forage a tubulure continue
US6814142B2 (en) Well control using pressure while drilling measurements
US10591623B2 (en) Multilateral well sensing system
US20120186873A1 (en) Well drilling method utilizing real time response to ahead of bit measurements
US20070221407A1 (en) Permanent downhole deployment of optical sensors
US20180202281A1 (en) Locating wellbore flow paths behind drill pipe
US20130087388A1 (en) Wellbore influx detection with drill string distributed measurements
US20180135365A1 (en) Automatic managed pressure drilling utilizing stationary downhole pressure sensors
AU2019325988B2 (en) Time division multiplexing of distributed downhole sensing systems
US8944162B2 (en) Ambient-activated switch for downhole operations
US10246996B2 (en) Estimation of formation properties based on fluid flowback measurements
NO20161852A1 (en) Molecular Factor Computing Sensor for Intelligent Well Completion
WO2011043763A1 (fr) Procédé de forage de puits utilisant une réponse en temps réel avant des mesures de foret
NO20240022A1 (en) Erosion prediction for downhole tools
CA2482487C (fr) Installation permanente de capteurs optiques dans un trou de forage

Legal Events

Date Code Title Description
WWE Wipo information: entry into national phase

Ref document number: 201180071386.X

Country of ref document: CN

121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 11866637

Country of ref document: EP

Kind code of ref document: A1

ENP Entry into the national phase

Ref document number: 2011369403

Country of ref document: AU

Date of ref document: 20110602

Kind code of ref document: A

REEP Request for entry into the european phase

Ref document number: 2011866637

Country of ref document: EP

WWE Wipo information: entry into national phase

Ref document number: 2011866637

Country of ref document: EP

ENP Entry into the national phase

Ref document number: 2837859

Country of ref document: CA

NENP Non-entry into the national phase

Ref country code: DE

ENP Entry into the national phase

Ref document number: 2013158132

Country of ref document: RU

Kind code of ref document: A

REG Reference to national code

Ref country code: BR

Ref legal event code: B01A

Ref document number: 112013030718

Country of ref document: BR

ENP Entry into the national phase

Ref document number: 112013030718

Country of ref document: BR

Kind code of ref document: A2

Effective date: 20131128

点击 这是indexloc提供的php浏览器服务，不要输入任何密码和下载