WO2014183187A1 - Procédé et appareil de placement de puits de forage de fond de trou - Google Patents

Procédé et appareil de placement de puits de forage de fond de trou Download PDF

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Publication number
WO2014183187A1
WO2014183187A1 PCT/CA2013/050374 CA2013050374W WO2014183187A1 WO 2014183187 A1 WO2014183187 A1 WO 2014183187A1 CA 2013050374 W CA2013050374 W CA 2013050374W WO 2014183187 A1 WO2014183187 A1 WO 2014183187A1
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WO
WIPO (PCT)
Prior art keywords
acoustic
fiber bragg
wellbore
sources
bragg grating
Prior art date
Application number
PCT/CA2013/050374
Other languages
English (en)
Inventor
Aaron W. LOGAN
Justin C. LOGAN
Original Assignee
Evolution Engineering 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 Evolution Engineering Inc. filed Critical Evolution Engineering Inc.
Priority to PCT/CA2013/050374 priority Critical patent/WO2014183187A1/fr
Publication of WO2014183187A1 publication Critical patent/WO2014183187A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/04—Directional drilling
    • E21B7/046—Directional drilling horizontal drilling
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes
    • E21B47/095—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes by detecting an acoustic anomalies, e.g. using mud-pressure pulses
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/22—Transmitting seismic signals to recording or processing apparatus
    • G01V1/226—Optoseismic systems

Definitions

  • This invention relates to subsurface drilling, specifically to apparatus and method for downhole wellbore placement. Embodiments are applicable, for example, to drilling wells for recovering hydrocarbons.
  • Wellbores are made using surface-located drilling equipment which drives a drill string that eventually extends from the surface equipment to the formation or subterranean zone of interest.
  • the drill string can extend thousands of feet or meters below the surface.
  • the terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore.
  • Drilling fluid usually in the form of a drilling "mud" is typically pumped through the drill string.
  • the drilling fluid cools and lubricates the drill bit and also carries cuttings back to the surface.
  • Drilling fluid may also be used to help control bottom hole pressure to inhibit hydrocarbon influx from the formation into the wellbore and potential blow out at surface.
  • Bottom hole assembly is the name given to the equipment at the terminal end of a drill string.
  • a BHA may comprise elements such as: apparatus for steering the direction of the drilling (e.g. a steerable downhole mud motor or rotary steerable system); sensors for measuring properties of the surrounding geological formations (e.g. sensors for use in well logging); sensors for measuring downhole conditions as drilling progresses; systems for telemetry of data to the surface; stabilizers; heavy weight drill collars, pulsers and the like.
  • the BHA is typically advanced into the wellbore by a string of metallic tubulars (drill pipe).
  • Telemetry information can be invaluable for efficient drilling operations.
  • telemetry information from a downhole probe may be used by a drill rig crew to make decisions about controlling and steering the drill bit to optimize the drilling speed and trajectory based on numerous factors, including legal boundaries, locations of existing wells, formation properties, hydrocarbon size and location, etc.
  • a crew may make intentional deviations from the planned path as necessary based on information gathered from downhole sensors and transmitted to the surface by telemetry during the drilling process.
  • the ability to obtain real time data allows for relatively more economical and more efficient drilling operations. [0006] In many cases it is not only critical to be able to track the drilling of boreholes at subsurface locations, but also to be able to determine the relative location of one borehole, such as a reference well, to another borehole being drilled.
  • Magnetic ranging may be used to determine the relative position of one well with respect to another, or to some surface reference, using magnetic measurements.
  • Various magnetic ranging technologies are available in the marketplace. Active ranging utilizes a precisely positioned electromagnetic source or a rotating rare-earth magnet fixed to the BHA. In areas where magnetic interference may be prevalent, systems have used Gravity MWD (GMWD) providing azimuth with two sets of directional survey accelerometers to determining BHA bend and wellbore positioning. In passive magnetic ranging or magnetostatic methods, the current state of magnetism of a casing of the reference well is measured.
  • GMWD Gravity MWD
  • Magnetic ranging has been used for a variety of applications such as but not limited to, positioning of blow out wells, planned (or avoidance) of intersection of one well with another, wellbore placements for Steam Assisted Gravity Drainage or SAGD, and construction of wellbores for nuclear wastes.
  • Other wellbore placement systems include a sonic telemetry system utilizing time of flight (TOF) ranging as described in CA 2692907.
  • TOF time of flight
  • US 2010/0200296 describes another wellbore placement system, where a series of acoustic generators are deployed in a drill string and their emitted signal is picked up by geophones on the earth's surface; the subsurface positions of these acoustic generators are then computed by a complex geophone position and time of flight data analysis.
  • optical fiber has also assisted in measurement of seismic changes.
  • WO 2012/123760 describes a method involving optical fiber deployed along substantially the entire length of the wellbore to provide distributed acoustic sensing and detecting the acoustic response to seismic stimulus.
  • the data can provide information related to time of arrival of incident seismic waves at various sensing portions of fiber and also reflections of seismic waves to ascertain a seismic profile.
  • DAS distributed acoustic sensors
  • WO2010/136768 describes the use of measurement of acoustic signals and monitoring sections of fiber in the vicinity of the drill as it advances through a well to provide real time feedback to the driller.
  • WO2012/094086 describes use of fiber optic sensors for monitoring vibration in the downhole environment.
  • Fiber optic sensors have been applied in MWD applications as described in CA 2664523 utilizing optical fiber to measure parameters of interest and to communicate data.
  • the invention has several aspects.
  • One aspect provides methods for downhole wellbore placement during drilling.
  • Another aspect provides apparatus for downhole wellbore placement during drilling.
  • Another aspect provides computer readable media storing computer executable instructions for implementing methods for drilling.
  • Figure 1 is a schematic view of a drilling operation showing placement of two wellbores in close proximity according to an example embodiment.
  • Figure 1A shows a schematic exploded view of section 1A in Figure 1.
  • Figure IB schematically shows the optical processing equipment in Figure 1.
  • Figure 1C is a graphical representation showing the reflectivity profile of example fiber Bragg grating sensors.
  • Figure 2 is a schematic view showing steam envelope potential problems and/or errors that may occur when drilling a SAGD pair.
  • Figure 3 is a cross sectional view in the plane A-A of a portion of the wellbores shown in Figure 1 showing co-planar alignment and wellbore placement requirements.
  • Figure 4 shows schematically a noise generating device producing an acoustic signature received by a secondary wellbore downhole fiber Bragg grating.
  • Figures 5A to 5D show schematically a number of different example noise sources.
  • Figure 6 is a schematic view according to another example embodiment showing a noise generating device producing an acoustic signature received by a fiber Bragg grating on the surface.
  • Figure 7 is a 3D isometric view of multiple SAGD fiber Bragg grating wellbores. Description
  • Figure 1 shows schematically an example drilling operation 100, in which it is desired to drill a plurality of boreholes having a specified geometric relationship to one another. For example, it may be desired to drill an array of boreholes that are all parallel to one another.
  • the illustrated embodiment shows Steam Assisted Gravity Drainage (SAGD) drilling but this is just exemplary, the invention is not limited to drilling wells for SAGD.
  • SAGD Steam Assisted Gravity Drainage
  • a primary wellbore 110 with a horizontal section 110A is drilled through a formation of interest 120. Drilling can be done, for example, by means of directional drilling techniques known to those skilled in the art.
  • Horizontal section 110A may be equipped with a ranging device 130.
  • Ranging device 130 may be in the form of optical fiber 140.
  • Optical fiber 140 may extend substantially through the entire length of wellbore 110 and horizontal section 110A. In some embodiments, optical fiber 140 may extend through the entirety of wellbore 110 and horizontal section 110A. Installation of ranging device 130 within wellbore 110 and horizontal section 110A may be conducted using methods known to those skilled in the art.
  • Optical fiber 140 has a core 140A and cladding 140B. Optical fiber 140 may also include additional coatings or protective layers as desired.
  • One or more fiber Bragg gratings 150 are formed within optical fiber 140 using methods known to those skilled in the art. In some embodiments, fiber Bragg gratings 150 are spaced apart from one another by distances in the range of a few meters to 100 meters or more. In a preferred example embodiment, SAGD boreholes containing fiber Bragg gratings are spaced apart from one another by a distance in the range of 5 to 20 meters.
  • Optical fiber 140 connects fiber Bragg gratings 150 to optical signal processing equipment 160A.
  • Fiber Bragg grating sensors provide a periodic refractive index variation in the core of an optical fiber that causes reflection of a narrow wavelength band of light.
  • a fiber Bragg grating 150 has a maximum reflectivity at a central reflectivity wavelength and transmits other wavelengths.
  • Each fiber Bragg grating 150 reflects a narrow wavelength band of light having a central wavelength.
  • Each fiber Bragg grating 150 may be constructed to reflect light in a different wavelength band and central wavelength such that the signals from different fiber Bragg gratings 150 may be detected using Wavelength Division Multiplexing (WDM) techniques.
  • WDM Wavelength Division Multiplexing
  • optical signal processing equipment 160A includes a broadband source of light 161 and appropriate equipment for coupling the light into optical fiber 140, (e.g. a coupler 162). Additionally, optical signal processing equipment 160A includes appropriate signal analysis equipment 163 for detecting and analyzing the return signals from fiber Bragg gratings 150.
  • broadband light 300 passes through optical fiber 140 until it reaches the first fiber Bragg grating 150-1.
  • First fiber Bragg grating 150-1 reflects a narrow wavelength band of light having a central wavelength ⁇ 1 .
  • Light 301 not reflected by first fiber Bragg grating 150-1 is transmitted toward a second fiber Bragg grating 150-2 which reflects a narrow wavelength band of light having a central wavelength ⁇ 2 .
  • Light 302 not reflected by the second fiber Bragg grating 150-2 is transmitted to the next fiber Bragg grating.
  • the process continues until light has passed by N fiber Bragg gratings resulting in N different reflected light signals each having a different wavelength.
  • the end of fiber optic 140 may be terminated in an anti-reflective manner.
  • Fiber Bragg gratings are well suited for use as sensor elements.
  • a measurand such as a dynamic strain induced by acoustic waves will induce a change in the fiber Bragg grating spacing and/or reflectivity characteristics, which changes the wavelength of the light reflected by the fiber Bragg grating.
  • the wavelength reflected by the fiber grating is directly related to the value (magnitude) of the measurand. Therefore, optical fiber 140 may be used to measure features such as acoustic fields at the locations of fiber Bragg gratings 150 by monitoring the wavelengths of light reflected by the different fiber Bragg gratings 150.
  • a system comprising a fiber optic sensor incorporating one or more fiber Bragg gratings may be used to detect acoustic fields at a precise location (or preferably multiple locations) within the wellbore.
  • fiber Bragg gratings deployed in one or more wellbores are used to localize sources of acoustic signals associated with the creation of other wellbores. This information may be used to steer drilling on the other wellbores to achieve a desired arrangement of two or more wellbores. Acoustic signals detected using fiber Bragg gratings may be used in combination with inputs from other sensors for more accurate placement measurement.
  • FIG. 1 shows an example secondary wellbore 170 being drilled using a drill rig 180 which drives a drill string 190. Any suitable directional drilling methods may be applied to guide the drilling of secondary wellbore 170 (including directional drilling methods known to those skilled in the art).
  • a bottom hole Assembly (BHA) 200 is attached to the bottom of drill string 190 and has a drill bit 210 attached to a bottom end thereof.
  • BHA 200 may comprise multiple sections of drill string 190 and may incorporate a measurement while drilling (MWD) system.
  • MWD measurement while drilling
  • fiber Bragg gratings 150 positioned within primary wellbore 110 will experience dynamic strain from the acoustic signals originating from BHA 200 within secondary wellbore 170.
  • Acoustic signals may, for example, be generated by the interaction of drill bit 210 with the formation it is drilling into, drilling fluid pulsations (e.g. pulsations generated by a mud hammer or other pulser that is optionally incorporated in BHA 200), sound generated by the operation of a mud motor driving the drill bit or the like. Sound propagates from BHA 200 to fiber Bragg gratings 150. The interaction of the sound with the fiber Bragg gratings causes dynamic strain on the fiber Bragg gratings.
  • This strain will cause wavelength shifts in the central wavelength of the narrow band of light reflected by fiber Bragg gratings 150.
  • the wavelength shifts may be processed to determine the amplitude and other characteristics (e.g frequency spectrum) of the acoustic fields causing the dynamic strain.
  • the central wavelength ⁇ ( ⁇ ) is shifted by an amount ⁇ ( ⁇ ) to a new wavelength ⁇ '( ⁇ ).
  • the wavelengths reflected by different fiber Bragg gratings 150 are separated and designed to provide a wavelength spacing such that when the central wavelength of one fiber Bragg grating 150 is shifted by a maximum amount associated with a maximum dynamic strain, the resulting reflected wavelength will still be in a desired band ⁇ which does not overlap with bands associated with any of the other fiber Bragg gratings 150. Therefore, as shown in Figure 1C, the shifted central wavelength ⁇ '( ⁇ ) for fiber Bragg grating 150-1, will always be within band coj , which does not overlap with any of bands ⁇ x> 2 .. ⁇ ⁇ ⁇ fiber Bragg gratings 150-2 .. 150-N, respectively.
  • the reflected optical signals ⁇ '( ⁇ ) .. ⁇ ⁇ '( ⁇ ) are provided via optical fiber 140 and coupler 162 to signal analysis equipment 163.
  • the return optical signals are directed to a wavelength-demultiplexer 400 (such as a selective filter, a set of selective filters, a spectrometer or the like).
  • wavelength-demultiplexer 400 provides separate outputs associated with different fiber Bragg gratings 150 to be analyzed using sensitive wavelength or phase discrimination equipment 402 which detects, demodulates and performs wavelength or phase discrimination to detect wavelength modulation due to acoustic signals detected at fiber Bragg gratings 150.
  • the output of wavelength or phase discrimination equipment 402 is provided to a processor/controller 404 for processing, storage in memory 405, display 406 to a user, or for any other desired use.
  • Processor 404 may be provided with a user interface 407 for user input and control.
  • Ranging device 130 including fiber Bragg gratings 150 and/or signal analysis equipment 163 may be provided by a commercially-available fiber Bragg grating sensor system. Examples of such systems include fiber Bragg grating sensors available from HiFi Engineering, Inc. of Calgary, Alberta, Canada, fiber integrators available from Optiphase, Inc. of Van Nuys, California as well as high performance computing processors available by multiple manufacturers in the industry. Signals from fiber Bragg gratings may be processed using such commercially-available fiber Bragg grating sensor systems to yield information regarding the relative positions and signal strengths of acoustic sources. Time of flight manipulations may then be conducted to determine the exact position of the sensors based on the signal strength and sensor relative position.
  • Processor 404 may be configured to localize acoustic sources based upon amplitude and/or other characteristics of acoustic signals detected at fiber Bragg gratings 150. In some embodiments, processor 404 may be configured to separately identify components of acoustic signals detected at fiber Bragg gratings 150 that arise from two or more distinct acoustic sources and to localize each of the sound sources based on the detected acoustic signals. Acoustic signals from different sources may be identified by their different acoustic signatures. For example, in one embodiment, detected acoustic signals are subjected to a frequency spectrum analysis (e.g. processed using a discrete Fourier transform algorithm).
  • a frequency spectrum analysis e.g. processed using a discrete Fourier transform algorithm
  • BHA 200 may comprise one or more acoustic signature generating devices located at known locations relative to drill bit 210.
  • Processor 404 may be configured to separately detect acoustic signal components arising from drill bit 210 and one or more separate acoustic signal generating devices.
  • Figure 2 schematically shows a portion of an array of wellbores for use in SAGD and illustrates why it is desirable to control the positions of the wellbores.
  • Figure 3 is a schematic cross section view of the horizontal section 11 OA of primary wellbore 110 and secondary wellbore 170 taken in the plane A- A in Figure 1.
  • secondary wellbore 170 is shown to be in close proximity and coplanar alignment to horizontal section 11 OA of primarily wellbore 110.
  • Primary wellbore 110 may be drilled using any suitable directional drilling method.
  • a first fiber Bragg ranging sensor array 130 is installed in primary wellbore 110. After first fiber Bragg ranging sensor array 130 has been installed it can be applied to localize another wellbore being drilled nearby wellbore 110.
  • another primary wellbore 110-1 may be drilled, using directional drilling so that it is oriented to be in the same horizontal plane and a distance x away from primary wellbore 110.
  • MWD measurements may be obtained from telemetry tools (not shown) in BHA 200 in order to determine inclination, azimuth and depth of BHA 200 during drilling.
  • One or more acoustic signals originating from points in BHA 200 within wellbore 110-1 during drilling are received by fiber Bragg gratings 150.
  • Optical signals ⁇ ' .. ⁇ ⁇ ' from fiber Bragg gratings 150 are detected and processed by processor 404. Since the location of each of fiber Bragg gratings 150 is known and the intensity of acoustic signals at these locations can be determined by processing optical signals ⁇ ' .. ⁇ ⁇ ', the distance of acoustic sources in or associated with BHA 200 from fiber Bragg gratings 150 may be determined.
  • distances between one or more acoustic sources and fiber Bragg gratings 150 are time-of-flight measurements such as measuring the relative acoustic phase at different fiber Bragg gratings 150 or determining the relative times at which recognizable acoustic features are detected at different fiber Bragg gratings 150. These distances may be used to determine whether wellbore 110-1 is progressing toward or away from wellbore 110. These distances may be used in conjunction with information from MWD measurements to better pinpoint the location of drill bit 210 and BHA 200 relative to wellbore 110.
  • the intensity of the acoustic signal near fiber Bragg grating 150-1 would be stronger than the intensity of the acoustic signal at other fiber Bragg gratings 150.
  • the difference in amplitude of the acoustic signal at different fiber Bragg gratings 150 will depend on how the acoustic signal is attenuated by the formation through which it passes.
  • Time of flight acoustic measurements may additionally or in the alternative indicate the position(s) of acoustic emitters in BHA 200. Time-of-flight measurements may be affected by variations in the speed of sound in the formation in which the wellbore are being made.
  • the properties of the formation can be expected to be fairly uniform between the boreholes in most cases.
  • the anomalies can be modeled and corresponding corrections or adjustments may be applied. Similar corrections are applied in the field of seismic prospecting.
  • Techniques used in seismic prospecting to model and correct for the presence of formations having different acoustic transmission properties may be applied also in the context of the present invention. As additional fiber Bragg gratings are installed in subsequent wellbores, the anomalies are easier to correct and adjust for due to the increase in sample size of the data used to model the correction.
  • the combination of MWD telemetry measurements and acoustic intensity measurements may be used to maintain the two wellbores 110 and 110-1 coplanar (e.g. in a horizontal plane) by applying corrections as to how BHA 200 is steered during drilling. The same process may be applied to drill additional primary wellbores in the same horizontal plane.
  • Ranging sensors 130 comprising optical fibers having fiber Bragg gratings may be installed within each wellbore.
  • the additional fiber Bragg sensors can receive acoustic signals from the operation of drill bit 210 and/or other acoustic sources in BHA 200. Relative distances from the acoustic sources can be determined from the acoustic signals (for example, by determining the amplitude of the acoustic signals at different fiber Bragg gratings 150 and/or by time-of-flight acoustic measurements as described above and assuming an attenuation function for the acoustic signals. This information can be used to calculate the position of drill bit 210 and BHA 200 relative to the existing wellbores.
  • a secondary wellbore 170 may be drilled, in the same manner as primary wellbore 110-1 using directional drilling.
  • the secondary wellbore may, for example, be drilled to have a horizontal section located in a plane vertical to one of the primary wellbores, for example, wellbore 110.
  • Secondary wellbore 170 is maintained during the drilling operation at a substantially fixed distance y from primary wellbore 110. Corrections to the steering of secondary wellbore 170 may be determined based on two independent measurements, namely: the relative position of the primary and secondary wellbores and the "normal" geometric measurement and location for secondary wellbore 170.
  • the acoustic signal(s) generated by BHA 200 in secondary wellbore 170 will now be received by two independent fiber optic lines each having fiber Bragg sensors, which in turn provide reflected optical signals to processor 404. Therefore, processor 404 will have access to multiple reference points in space that are not all located along the same line. The relative distances of these reference points to acoustic sources associated with BHA 200 can be determined from the intensities of the acoustic signals. This information in turn allows for determining the location of acoustic sources in BHA 200 by triangulation in 3D space relative to primary wellbores 110 and 110-1.
  • the determined 3D coordinates of BHA 200 may be used to determine whether secondary wellbore 170 may require a course correction by moving it in the up, down, left or right direction, relative to primary wellbore 110, in order to keep secondary wellbore 170 in a desired spacing and alignment with primary wellbore 110.
  • the necessary correction may be applied by steering drill bit 210 in any suitable manner.
  • Drilling other secondary wellbores may be done using the same process described above. As each additional wellbore is drilled and equipped with its own fiber Bragg grating sensors, the accuracy of 3D placement of other wellbores relative to the wellbores already drilled can be improved since the number of locations corresponding to fiber Bragg gratings 150 is increased and also covers a larger volume. This can provide multiple known reference points in space relative to the BHA during drilling, which will enable generating highly defined geometric placement and 3D location of live wellbores as seen in Figure 7.
  • Processor 404 may process received information characterizing the acoustic signals received at fiber Bragg gratings 150 to reverse triangulate a precise location of the noise source(s) from drilling another wellbore. This process may be performed continuously or periodically while wellbores are drilled. The result can be real time or near real time tracking of the path of the wellbore. This path can be compared to a desired path to determine whether corrections are necessary.
  • Corrections to the path of a wellbore being drilled may be presented in the form of information or instructions to a user on a display or may be communicated to the user by other means.
  • the user may apply the suggested corrections by processor 404 manually using user interface 407.
  • the corrections may be presented to the user on display 406 and directly applied to secondary wellbore 170 by means of control signals provided to a steering system being used to steer the drill bit 210 in the wellbore 170 being drilled.
  • a delay may be present between displaying on display 406 the correction determined by processor 404 and the application of the correction instructions to secondary wellbore 170.
  • a user may interrupt the execution of the determined corrections or may edit the corrections before execution.
  • the entire process of determining the corrections by processor 404 and the execution of the determined corrections on secondary wellbore 170 may be completely automated without human involvement.
  • the secondary wellbore may be drilled in close proximity and precise coplanar alignment to the primary wellbore using
  • FIG. 4 schematically shows various noise source generators during the operation of the drill in the secondary wellbore, that are received by the fiber Bragg gratings within horizontal section 110A of primary wellbore 110.
  • Noise can be generated from drill bit 210.
  • Noise may also be generated from BHA 200, which may include various acoustic sources (not shown). Additionally, noise may be generated using an independent acoustic signal generator 600 coupled to BHA 200.
  • Figures 5A-5D schematically show how several key components of BHA 200 may generate a large amount of acoustic or seismic noise.
  • the locations of acoustic sources within BHA 200 are known as the acoustic signatures (e.g. frequency spectra, dominant frequencies, etc.) of the sound emitted by these acoustic sources.
  • Figure 5 A shows how the drill bit 210 interface with the formation 120 may generate noise and vibration (dashed lines) during drilling causing micro seismic activity within the formation. This noise can be characterised and its signature can be monitored by the fiber Bragg gratings as described above.
  • Figure 5B shows how the mud motor (or mud/air hammer, or mud turbine) 510, which is essentially a cavitation pump, may generate an acoustic harmonic frequency in the drilling fluid due to its mechanical operation. This noise can be characterised and its signature can be monitored by the fiber Bragg gratings as described above.
  • Figure 5C shows how the MWD tool 520 may be a mud pulser, where its main form of telemetry to surface may be by restricted drilling fluid flow pressure pulses, the fluid pressure pulses are an acoustic wave that travels through the drilling fluid. These pulses may be random pulses as required for coding of information for telemetry to surface, or specifically controlled pulse sequences to generate a known acoustic signature. This noise can be characterised and its signature can be monitored by the fiber Bragg gratings as described above. [0063] Figure 5C also shows how the MWD tool 520 could be an Acoustic Telemetry MWD system, which by its nature emits an acoustic signal as its means of telemetry to surface.
  • This noise can be characterised and its signature can be monitored by the fiber Bragg gratings as described above.
  • an agitator may be used as a noise generating device.
  • Agitators may be provided in a BHA used for directional drilling.
  • An agitator can provide a vibration source in the BHA that will break the friction of the drill pipe and the wellbore during horizontal drilling. This may permit extended reach of the drill bit.
  • This vibration noise and micro seismic activity can be characterised and its signature can be monitored by the fiber Bragg gratings as described above.
  • the wellbore may be drilled using a modified BHA where an additional "low energy, continuous frequency noise source" 530 is directly coupled to the drill bit as a component of the bottom hole assembly, such as a collar or sub.
  • This low energy, continuous frequency noise source could be any number of devices specifically designed to generate noise. For example, it could be a pure mechanical drilling fluid propelled cam shaft vibrator/impactor that emits a known low energy continuous frequency noise, or a pure mechanical fluid flow activated poppet orifice fluid pressure pulse generator, or other specifically designed mechanical or electromechanical device to generate a known and controllable noise.
  • a wide range of acoustic sources associated with drilling a well bore may be tracked using fiber Bragg sensor arrays. It is advantageous that at least some of the acoustic sources be controlled and continuous acoustic sources that produce sound having a known and easily distinguishable acoustic signature . Examples of such acoustic sources are controlled MWD pulse patterns and specifically designed acoustic generators integrated into the BHA.
  • the speed of sound in geological formations depends on the local characteristics of the formations through which the sound is propagating. This could lead to errors, especially in time of flight related measurements. Fortunately, in many practical applications the geological formations in which multiple wellbores are desired are fairly uniform in acoustic characteristics on the scale of the wellbores.
  • the acoustic noise generator and the fiber Bragg grating sensors may be located in the same geological formation or in geological formations having substantially similar characteristics.
  • time of flight related measurements may be more accurate than they would be in the case of acoustic propagation through formations having markedly different acoustic transmission properties since the acoustic noise, generated by any number of non-limited methods (controlled or random noise), travels through the same formation or substantially the same formation before arriving at the fiber Bragg grating sensors.
  • Figure 6 schematically shows another embodiment of the invention where one or more fiber Bragg grating sensor lines 700 are placed at or near the surface.
  • fiber Bragg grating sensor line 700 may be buried in a trench, laid on the surface or attached to the surface by affixing means such as spikes, rods or other means.
  • Surface sensor line 700 can be used in addition to or instead of other fiber Bragg grating sensor lines.
  • Surface sensor line 700 may be advantageous in getting better position information for wellbores especially for drilling the first few boreholes in a formation.
  • Surface sensor line(s) 700 may be surveyed in place to provide additional information for accurate placement of wellbores relative to survey coordinates.
  • the acoustic noise generated by any number of non-limited methods (controlled or random noise), may travel through the different formations between the noise generation source and the fiber Bragg grating sensor line 700 near the surface and impart an acoustic signature on fiber Bragg grating sensor line 700. Errors in time of flight related measurements contributed to change in the speed of
  • Horizontal section 11 OA in primary wellbore 110 may be equipped with an acoustic signature generating device and BHA 200 in secondary wellbore 170 may comprise a ranging device.
  • installed fiber Bragg sensor lines may be used for measuring temperature along the length of wellbores, measuring the inflow of hydrocarbon at discrete points along the length of the wellbores, and/or for determining the effectiveness of injected steam.
  • Fiber Bragg grating sensor lines may be used for monitoring and measuring various characteristics of a producing well (such as pressures, temperatures, seismic, and inline flow measurements), for wellbore performance and production monitoring as well as SAGD life cycle characterization.
  • Certain implementations of the invention comprise computer processors which execute software instructions which cause the processors to perform a method of the invention.
  • processors in a directional drilling system may implement the methods described herein by executing software instructions in a program memory accessible to the processors.
  • the invention may also be provided in the form of a program product.
  • the program product may comprise any tangible medium which carries a set of computer-readable signals comprising instructions which, when executed by a data processor, cause the data processor to execute a method of the invention.
  • Program products according to the invention may be in any of a wide variety of forms.
  • the program product may comprise, for example, physical media such as magnetic data storage media including floppy diskettes, hard disk drives, optical data storage media including CD ROMs, DVDs, electronic data storage media including ROMs, PROMs, EPROMs, flash RAM, or the like.
  • the computer-readable signals on the program product may optionally be compressed or encrypted.
  • connection means any connection or coupling, either direct or indirect, between two or more elements; the coupling or connection between the elements can be physical, logical, or a combination thereof.

Abstract

La présente invention concerne un procédé de forage de multiples puits de forage proches les uns des autres qui comprend la fourniture d'un puits de forage primaire ; qui est équipé d'une ligne de capteurs de réseau de Bragg sur fibre (FBG). La ligne de capteur FBG s'étend le long d'au moins une partie du puits de forage primaire. Le procédé fore au moins un puits de forage secondaire à l'aide d'un forage dirigé. Les données de la ligne de capteurs FBG sont traitées pour déterminer les emplacements de sources acoustiques correspondant au forage dirigé par rapport à la ligne de capteurs FBG. Les emplacements des sources acoustiques sont utilisés pour comparer la trajectoire du puits de forage secondaire à une trajectoire souhaitée. Des corrections de la trajectoire peuvent être effectuées lorsque le puits de forage secondaire est foré. Les procédés peuvent être appliqués, par exemple, au forage de formations de puits de forage pour des applications de vapoextraction. L'invention concerne également un appareil et des produits-programmes informatiques associés.
PCT/CA2013/050374 2013-05-15 2013-05-15 Procédé et appareil de placement de puits de forage de fond de trou WO2014183187A1 (fr)

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WO2016138205A1 (fr) * 2015-02-27 2016-09-01 Schlumberger Technology Corporation Études sismiques à l'aide d'un capteur sismique
WO2017074399A1 (fr) * 2015-10-29 2017-05-04 Halliburton Energy Services, Inc. Procédés et systèmes utilisant un aimant mobile et des capteurs à fibre optique pour télémétrie
GB2535086B (en) * 2013-12-17 2020-11-18 Halliburton Energy Services Inc Distributed acoustic sensing for passive ranging
US10961843B2 (en) 2016-12-30 2021-03-30 Evolution Engineering Inc. System and method for data telemetry among adjacent boreholes

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WO2002057805A2 (fr) * 2000-06-29 2002-07-25 Tubel Paulo S Procede et systeme permettant de surveiller des structures intelligentes mettant en oeuvre des capteurs optiques distribues
WO2009146548A1 (fr) * 2008-06-03 2009-12-10 Schlumberger Technology Corporation Système et procédé permettant de déterminer les positions en fond de trou
US20100284250A1 (en) * 2007-12-06 2010-11-11 Halliburton Energy Services, Inc. Acoustic steering for borehole placement
WO2012067611A1 (fr) * 2010-11-17 2012-05-24 Halliburton Energy Services Inc. Appareil et procédé pour forer un puits

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WO2002057805A2 (fr) * 2000-06-29 2002-07-25 Tubel Paulo S Procede et systeme permettant de surveiller des structures intelligentes mettant en oeuvre des capteurs optiques distribues
US20100284250A1 (en) * 2007-12-06 2010-11-11 Halliburton Energy Services, Inc. Acoustic steering for borehole placement
WO2009146548A1 (fr) * 2008-06-03 2009-12-10 Schlumberger Technology Corporation Système et procédé permettant de déterminer les positions en fond de trou
WO2012067611A1 (fr) * 2010-11-17 2012-05-24 Halliburton Energy Services Inc. Appareil et procédé pour forer un puits

Cited By (5)

* 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
WO2016138205A1 (fr) * 2015-02-27 2016-09-01 Schlumberger Technology Corporation Études sismiques à l'aide d'un capteur sismique
WO2017074399A1 (fr) * 2015-10-29 2017-05-04 Halliburton Energy Services, Inc. Procédés et systèmes utilisant un aimant mobile et des capteurs à fibre optique pour télémétrie
US10920575B2 (en) 2015-10-29 2021-02-16 Halliburton Energy Services, Inc. Methods and systems employing a rotating magnet and fiber optic sensors for ranging
US10961843B2 (en) 2016-12-30 2021-03-30 Evolution Engineering Inc. System and method for data telemetry among adjacent boreholes

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