EP2715032A1 - Trépans de carottage et de forage à analyseur optique intégré - Google Patents

Trépans de carottage et de forage à analyseur optique intégré

Info

Publication number
EP2715032A1
EP2715032A1 EP11866449.9A EP11866449A EP2715032A1 EP 2715032 A1 EP2715032 A1 EP 2715032A1 EP 11866449 A EP11866449 A EP 11866449A EP 2715032 A1 EP2715032 A1 EP 2715032A1
Authority
EP
European Patent Office
Prior art keywords
bit
core sample
light
optical
analyzer
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP11866449.9A
Other languages
German (de)
English (en)
Other versions
EP2715032A4 (fr
Inventor
Gary E. Weaver
Clive D. Menezes
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Halliburton Energy Services Inc
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
Publication of EP2715032A1 publication Critical patent/EP2715032A1/fr
Publication of EP2715032A4 publication Critical patent/EP2715032A4/fr
Withdrawn legal-status Critical Current

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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/002—Survey of boreholes or wells by visual inspection
    • E21B47/0025—Survey of boreholes or wells by visual inspection generating an image of the borehole wall using down-hole measurements, e.g. acoustic or electric
    • 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
    • E21B10/00—Drill bits
    • E21B10/02—Core bits
    • 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
    • E21B10/00—Drill bits
    • E21B10/46—Drill bits characterised by wear resisting parts, e.g. diamond inserts
    • E21B10/54—Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
    • 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
    • E21B10/00—Drill bits
    • E21B10/62—Drill bits characterised by parts, e.g. cutting elements, which are detachable or adjustable
    • 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
    • E21B25/00—Apparatus for obtaining or removing undisturbed cores, e.g. core barrels or core extractors
    • 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
    • E21B47/002—Survey of boreholes or wells by visual inspection
    • 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
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/113—Locating fluid leaks, intrusions or movements using electrical indications; using light radiations
    • 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
    • E21B49/005—Testing the nature of borehole walls or the formation by using drilling mud or cutting data
    • 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

  • Formation coring is well known in the oil and gas industry.
  • a coring bit at the end of a drill string cuts a columnar core from the bottom of the borehole.
  • the core passes into an inner barrel as it is cut.
  • the inner barrel can then be lifted to transport the core to the surface for laboratory analysis.
  • Characteristics such as formation permeability, porosity, fluid saturations, etc., can usually be determined accurately in this way.
  • Such information is considered to be essential for many companies involved in the search for petroleum, gas, and mineral reserves. Such data may also be useful for construction site evaluation and in quarrying operations.
  • cores are preferably obtained in a continuous fashion to preserve the core samples in as pristine a state as possible.
  • Standard lengths for the inner barrel (and hence the core sample) are 30 feet (9 meters), 60 feet (18 meters), and 90 feet (27 meters). If anything goes awry with the coring process, it could be many hours before the problem is discovered. Moreover, the failure to detect and correct such problems in a timely fashion can necessitate days of additional effort to replace the lost core sample material.
  • Fig. 2 shows an illustrative coring bit cross-section
  • Fig. 3 shows a throat of an illustrative coring bit
  • Fig. 4A shows the principles of operation of an illustrative optical analyzer
  • Fig. 5 shows the principles of operation of an illustrative MOE-based detector
  • Fig. 6 shows the principles of operation of an optical analyzer with dual windows
  • Fig. 7 shows an illustrative drill bit
  • Fig. 8 show r s an illustrative drill bit impact arrester
  • Fig. 9 is a flow diagram for an illustrative coring method.
  • At least some disclosed drill bit embodiments include fixed cutting teeth that form a borehole through a formation as the bit rotates, and at least one impact arrester that rides in grooves formed by the cutting teeth.
  • An integrated optical analyzer illuminates the formation through a window in the impact arrester and analyzes light reflected from the formation. Light travels between the window and the optical analyzer via a transmission system that may employ one or more optical fibers.
  • the optical analyzer may employ multiple filters including one or more multivariate optical elements designed to measure spectral characteristics of selected fluids and/or rock types. Position and orientation sensors can be included to enable the optical measurements to be presented as an image log.
  • At least some coring bit embodiments cut a core sample from the formation and perform optical analysis and imaging of the core sample's surface as it is acquired. Axially-spaced windows enable the coring rate to be accurately measured and compared to the bit's rate of motion to verify that the coring process is proceeding satisfactorily.
  • the tool orientation may be specified in terms of a tool face angle (a.k.a. rotational or azimuthal orientation), an inclination angle (the slope), and a compass direction, each of which can be derived from measurements by magnetometers, inclinometers, and/or accelerometers, though other sensor types such as inertial sensors and gyroscopes may additionally or alternatively be used to determine position as well as orientation.
  • the tool includes a 3 -axis fluxgate magnetometer and a 3 -axis acceierometer. As is known in the art, the combination of those two sensor systems enables the measurement of the tool face angle, inclination angle, and compass direction.
  • the tool face and hole inclination angles are calculated from the acceierometer sensor output.
  • the magnetometer sensor outputs are used to calculate the compass direction.
  • the drill bit 1 14 may be a "coring bit" designed to obtain a core sample.
  • the drill bit 1 14 may be a fixed cutter bit such as a poiycrystallme diamond compact (PDC) bit.
  • Fig. 2 is a side section view of a lower portion of an illustrative coring bit embodiment having a construction similar to that described in U.S. Patent No. 6,394,196 to Fanuel et al., which is hereby incorporated herein by reference in its entirety.
  • the drill bit 114 includes a cutter assembly 202 attached to an end of an outer tube 200.
  • the drill bit 114 also includes an inner tube 206 mounted within the outer tube 200 for receiving a core sample cut by the cutter assembly 202.
  • the drill bit 114 also includes a split ring 208 disposed at a front end of the inner tube 206 for gripping and/or grasping the core sample.
  • a flow space between the outer tube 200 and the inner tube 206 conveys drilling fluid through fluid channels in the bit to a bottom of the borehole.
  • Alternative bit embodiments include nozzles and/or liquid jet cutters to direct the drilling fluid as it exits from the bit.
  • the core sample enters the inner tube 206 as the bit moves forward along the axis 204.
  • the drill bit 1 14 of Fig. 2 includes an optical analysis system 210 including a window 212, an analyzer 216, and an optical transmission system 214 connected between the window 212 and the analyzer 216.
  • the window 212 is located on an inner surface of the core bit 202 such that the window 212 is proximate to a core sample being acquired by the drill bit 1 14.
  • the optical transmission system 214 communicates light from the analyzer 216 to the core sample, and communicates reflected light from the core sample to the analyzer 216.
  • the analyzer 216 analyzes the received reflected light to determine at least one characteristic of the core sample and/or form an image of the core sample.
  • Fig. 3 shows the throat of drill bit 1 14 as it acquires a core sample 300.
  • the core sample 300 is entering the inner tube 206 of the drill bit 114 as it gets cut from the floor of the borehole.
  • the window 212 is a distance 'D' from the core sample being acquired by the drill bit 1 14.
  • the distance D is expected to be, on average, no more than about 1/32 of an inch (0.8 millimeter) such that the light from the window can readily penetrate the drilling fluid and be reflected from the core sample 300.
  • the optical transmission system 214 includes a pair of optical fibers 302A and 302B.
  • the optical fiber 302A conveys light 304 from the analyzer 216 (see Fig. 2) to the core sample 300 via the window 212
  • the optical fiber 302B conveys light reflected from the core sample 300 via window 212 to the analyzer 216.
  • Fig. 4A is a diagram depicting one embodiment of the optical analysis system 210.
  • the analyzer 216 includes a light source 400, a detector system 402, a processor 404, and a telemetry system 406.
  • the optical transmission system 214 includes the pair of optical fibers 302A and 302B shown in Fig. 3 and described above.
  • the light source 400 produces electromagnetic radiation in the form of light.
  • the light may be, for example, infrared (IR) light having wavelengths between about 780 nanometers and approximately 1000 micrometers, visible light having wavelengths between about 380 nanometers and approximately 780 nanometers, and/or ultraviolet (UV) light having wavelengths between about 10 nanometers and approximately 380 nanometers.
  • IR infrared
  • UV ultraviolet
  • Suitable light sources include electrically heated filaments, arc lamps, solid state LEDs, to name just a few. Other suitable light sources are also well known and commercially available.
  • Light from light source 400 is directed into the optical fiber 302 A as a light beam 304.
  • the optical fiber 302A conveys the light beam 304 from the analyzer 216 to the window 212.
  • the window 212 is located on an inner surface of the core bit 202 (see Figs. 2 and 3) and proximate the core sample 300 being acquired by the drill bit 114.
  • the window 212 is substantially transparent to the light 304 exiting the optical fiber 302 A, and is preferably made of a scratch resistant material that has a high resistance to friction and abrasion.
  • the window 212 may be formed of or include, for example, sapphire or diamond.
  • Some or all of the light beam 304 exiting the optical fiber 302A passes through the window 212 and strikes the core sample 300. A. portion of the light 304 striking the core sample 300 reflects from the core sample 300, passes through the window 212, and enters the optical fiber 302B as the light 306. The optical fiber 302B conveys the light 306 reflected from the core sample 300 to the analyzer 216.
  • the detector system 402 receives the light 306 reflected from the core sample 300.
  • the detector system 402 produces an output signal dependent upon a characteristic of the received light 306.
  • the output signal may be, for example, an electrical signal such as a voltage or current.
  • the detector system 402 includes one or more one multivariate optical elements (MOEs) to define the light characteristic(s) that are measured by the detector system.
  • MOEs multivariate optical elements
  • the processor 404 also receives the output signal produced by the detector system 402, digitizes it, associates it with a tool face angle and/or a bit depth, and combines it with other measurements for that position to improve measurement quality. For additional measurement accuracy, the processor 404 also controls the light source 400 to regulate its temperature and/or intensity. The processor may further use the measurements to determine the core's characteristics in situ, including for example, rock type, hydrocarbon type, water concentration, porosity, and/or permeability. The processor can further use the measurements to construct an image of the core sample's surface. As the drill bit 114 cuts the core sample 300, the window 212 follows a helical path around the core sample, forming a two dimensional area over which the processor can acquire measurements to image the core.
  • At least some detector system embodiments employ one or more MOEs to determine whether the spectrum of the reflected light matches the spectral signature of one or more known materials.
  • one MOE may be designed to detect the spectral signature of methane, while another MOE detects the spectral signature of a light hydrocarbon.
  • other MOEs can be used to detect, e.g., long-chain hydrocarbons, water, C02, sulfur compounds, shale, silicates, or carbonates.
  • the detector can determine intensities of light passing through an MOE and reflected from an MOE to obtain a measure of how much of the given material is illuminated by the light beam 304. Additional details regarding MOE detectors and their usage can be found in, e.g., U.S. Patent No.
  • the detector can employ filters, dispersion gratings, and/or prisms to measure the spectrum of the reflected light. Such spectral measurements can be used for calibration and performing analysis of those materials for which no MOE has been specifically included.
  • Porosity is a measure of how much fluid- or gas-filled volume there is per unit volume of rock. For example, 20% porosity means that 20% of the volume is filled with fluid or gas.
  • Permeabi lity is a measure of resistance to fluid flow, i.e., how easily fluids or gases can propagate through the formation. As a general rule (though not an inviolate one), the more porous the formation, the higher its permeability. Saturation is a measure of what percentage of the formation fluids is water as opposed to hydrocarbon liquids or gases.
  • the processor 404 may also or alternatively use the output signal produced by the detector system 402 to form a surface image of the core sample 300.
  • the window 7 212 is turning in a helical path about an outer surface of the core sample 300.
  • the intensity of the light 306 reflected from the core sample 300 and other spectral measurements obtained by the detector system 402 expectedly varies with the texture of the surface of the core sample 300.
  • the processor 404 is configured to track the movement of the drill bit 1 14 (both the rotational motion about the axis 204 and the linear motion parallel to the axis 204), enabling the processor 404 to associate the intensity measurements produced by the detector system 402 with corresponding positions on the outer surface of the core sample 300, Displaying the intensity measurements as pixels having different levels of gray, or different colors, at positions on a screen corresponding to their positions on the outer surface of the core sample 300 will expectedly create an image of the outer surface of the core sample 300 on the screen.
  • the telemetry system 406 communicates information by sending and receiving data signals.
  • the telemetry system 406 receives data signals conveying instructions or commands for the processor 404 to carry out, and sends data signals conveying data from the processor 404 indicative of the one or more characteristics of the core sample 300 determined by the processor 404.
  • the data signals may be, for example, radio signals conducted via radio waves, electrical signals conveyed via one or more conductors, optical signals conveyed via one or more optical fibers, acoustic signals conveyed via the tool body, or pressure -pulse signals conveyed via the fluid flow.
  • Fig. 4B is a diagram depicting an alternative embodiment of the optical analysis system 210 where the optical transmission system 214 includes a single optical fiber 302.
  • the analyzer 216 further includes a beam splitter 420. Some of the light produced by the light source 400 passes through the beam splitter 420, emerges from the beam splitter 420, and enters the optical fiber 302 as the light 304. Some or all of the light 304 exiting the optical fiber 302 passes through the window 212 and strikes the core sample 300. A portion of the light 304 striking the core sample 300 reflects from the core sample 300, passes through the window 212, and enters the optical fiber 302 as reflected light 306.
  • the optical fiber 302 conveys the light 306 reflected from the core sample 300 to the analyzer 216, where the beam splitter directs at least some of the reflected light 422 to the detector system 402.
  • the beam splitter inherently induces some intensity losses to the light beam, but this embodiment may be preferred where the physical size of the optical transmission system 214 is a key factor.
  • Fig. 5 is a diagram of an illustrative defector system 402. in the embodiment of Fig. 5, the detector system 402 includes a wheel 500 including multiple filters and/or multivariate optical elements (MOEs) 502 disposed about a periphery of the wheel 500.
  • the wheel 500 rotates about an axis 504, bringing each filter or MOE successively into the path of the reflected light 306 or reflected light 422 reaching the detector system.
  • a light sensor 506 measures the intensity of the light passing through (or alternatively, reflected from) each filter or MOE in the wheel.
  • the light sensor 506 may be, for example, coupled to an analog-to-digital converter that produces a value included in the output signal.
  • the processor 404 (see Fig, 4A) is configured to determine which MOE 502 the light 306 (422) has passed through, and processes the output signal accordingly.
  • quantum-effect photodetectors such as photodiodes, photoresistors, phototransistors, photovoltaic ceils, and photomultiplier tubes
  • thermal-effect photodectors such as pyroelectric detectors, Golay ceils, thermocouples, thermopiles, and thermistors.
  • quantum-effect photodetectors are semiconductor based, e.g., silicon, InGaAs, PbS, and PbSe.
  • One contemplated tool embodiment employs a combined detector made up of a silicon photodiode stacked above an InGaAs photodiode. In tools operating in only the visible and/or near infrared, both quantum-effect photodetectors and thermal-effect photodetectors are suitable. In tools operating across wider spectral ranges, thermal-effect photodetectors are preferred.
  • the detector system 402 may also include a second light detector (not shown) responsive to light reflected from each of the MOEs 502 when the MOEs 502 pass through the path of the light 306 (422).
  • the second light detector may be coupled to an analog-to-digital converter that produces a value included in the output signal.
  • Fig. 6 is a diagram depicting an illustrative embodiment of the optical analysis system 210 having two axially-separated windows 2I2A and 2I2B. That is, the window's 212A and 212B are spaced apart from one another along the longitudinal axis 204 of the drill bit 114.
  • the optical analysis system 210 also includes a second pair of optical fibers 302C and 302D, and the analyzer 216 includes two detector systems 402A and 402B.
  • a portion of the light produced by the light source 400 enters the optical fiber 302A as the light 304, and another portion of the light produced by the light source 400 enters the optical fiber 302C as light 600.
  • the optical fiber 302A conveys the light 304 to the window 212A
  • the optical fiber 302C conveys the light 600 to the window 212B
  • a portion of the light 304 striking the core sample 300, reflecting from the core sample 300, and passing through the window 212A enters the optical fiber 302B as the light 306.
  • the optical fiber 302B conveys the light 306 reflected from the core sample 300 to the detector system 402 A.
  • the optical fiber 302D conveys the light 306 reflected from the core sample 300 to the detector 402B.
  • the processor 404 receives the output signals produced by the detector systems 402A and 402B and determines from each an image of the core sample. For example, the intensity of the light 306 and the light 602 reflected from the core sample 300 and reaching the respective detector systems 402A and 402B expeciedly varies with the texture of the surface of the core sample 300. In the embodiment of Fig. 6, a specific region of texture would to move past the window 212A first, then past the window 212B. The axial offset between windows is known, and by determining the time offset required to align portions of the two images, the processor can determine to a high precision the rate at which the core sample is entering into the inner barrel.
  • This "coring rate" can be compared to the bit's rate of motion as measured by inertia- sensors or other means.
  • a rate rn.ism.atch can be readily detected and used to quickly alert the operators of a potential issue with the coring process.
  • the operators can then act to address the issue and correct any problems before any substantial core losses occur.
  • the operators can vary the rotation rate and the weight-on-bit to restore smooth core cutting, or possibly retrieve the coring assembly to correct any mechanical issues.
  • the focus of the foregoing discussion has been on coring bits with integrated spectral analyzers. However, the spectral analyzers need not be focused on the core sample, but could alternatively be focused on the floor of the borehole to characterize the formation as soon after it- has been exposed as possible. Such a configuration would also be applicable to non-coring, fixed cutter bits.
  • Fig, 7 is an isometric view of a fixed cutter drill bit 700 for engaging and removing adjacent portions of a downhole formation at the bottom of a borehole.
  • Illustrative drill bit 700 includes a steel body 702 having multiple blades 704. Multiple cutting teeth 706 are disposed on cutting edges of each of the blades 704 to form the borehole through the formation as the drill bit 700 rotates.
  • the cutter inserts may be poly crystalline diamond compact (PDC) cutters seated in the blades 704. As the bit rotates, the cutting teeth 706 create grooves in the borehole floor.
  • PDC poly crystalline diamond compact
  • impact arresters 708 Positioned behind at least some of the teeth are impact arresters 708, i.e., stabilizing projections that ride in the grooves to reduce bit vibration. More detail regarding the design and use of impact arresters is available in U.S. Patent No. 5,090,492 to O 'Hanlon et al., incorporated herein by reference.
  • the average distance between the impact arresters and the formation can be less than 1/32 inch (0.8 millimeter).
  • one of these impact arresters 708 is equipped with a diamond or sapphire window 212.
  • the window is slightly inset and positioned slightly towards the trai ling edge of the impact arrester to provide some protection against wear.
  • An optical transmission system 214 communicates light through the blade between the window 212 and an optical analyzer.
  • the optical analysis system 210 operates as described above to determine at least one characteristic of the formation at the bottom of the wellbore and/or to form an image of a cylindrical portion of the formation.
  • Some bit embodiments may locate the window in a junk slot and/or in a flow nozzle to measure the characteristics of the drilling fluid before or after it interacts with the formation.
  • existing fixed cutter bit may be retrofitted with an optica! analysis system 210 by positioning the system in the space formerly reserved for a flow nozzle.
  • Fig. 8 is a side elevation view of one embodiment of a representative one of the impact arresters 708 of Fig. 7.
  • the impact arrester 708 is substantially cylindrical and has threaded end 800 and a rounded end 802, The threaded end 800 is installed in a threaded hole in the corresponding blade 704 of Fig. 7.
  • the cutting teeth 706 remove material from a formation 804 at a bottom of a wellbore.
  • the impact arrestor 708 follows a preceding cutting tooth 706.
  • the rounded end 800 of the impact arrestor 708 is adapted to follow a drilling slope formed in an exposed surface 806 of the formation 804 by the corresponding cutting tooth 706, and to ride snuggly in a groove cut in the exposed surface 806 by the corresponding cutting tooth 706.
  • the rounded end 802 of the impact arrestor 708 has a wear resistant coating 808 on an outer surface.
  • the coating 808 may be or include an extremely hard material such as tungsten carbide, natural diamonds, and/or man-made poiycrystalline diamond such as polycrystalline diamond compact (PDC) or thermally stable diamond (TSD).
  • the illustrated impact arrestor 708 includes a conduit 810 extending through the impact arrestor 708 from the threaded end 800 to the rounded end 802.
  • the window 212 of the optical analysis system 210 is positioned at an end of the conduit 810 in the rounded end 802.
  • the drill bit 700 of Fig. 7 has a conduit 812 that passes through the corresponding blade 704 and aligns with the conduit 810 of the impact arrestor 708.
  • the conduit 812 meets the conduit 810 of the impact arrester 708 at the threaded end 800 of the impact arrester 708.
  • the optical fiher(s) 302 of the optical transmission system 214 are positioned in the conduit 810 of the impact arrester 708 and extend through the impact arrestor 708 as indicated in Fig. 8.
  • some of the light produced by the light source 400 of Fig. 4B passes through the conduit 810 in the drill bit 700 and enters the optical fiber 302 as the light 304.
  • Some or ail of the light 304 exiting the optical fiber 302 passes through the window 212 and strikes the exposed surface 806 of the formation 804.
  • A. portion of the light 304 striking the exposed surface 806 reflects from the exposed surface 806, passes through the window 212, and enters the optical fiber 302 as reflected light 306.
  • the optical fiber 302 conveys the light 306 reflected from the formation 804 to the analyzer 216 (see Fig. 4B).
  • the optical analysis system 210 operates as described above to determine at least one characteristic of the formation 804 at the bottom of the wellbore.
  • the window 212 of the optical analysis system 210 may be positioned in the impact arrestor 708 such that the window 212 is slightly above the exposed surface 806 of the formation 804, and the optical analysis system 210 may analyze drilling fluid located between the window 212 and the exposed surface 806,
  • Fig. 9 is a flow chart of an illustrative method 900 for obtaining a core sample.
  • a first block 902 of the method 900 light is directed at the core sample as the core sample is being collected. At least a portion of the light reflected from the core sample is received during a block 904.
  • the received reflected light is analyzed to determine at least one characteristic of the core sample.
  • the core sample may be, for example, a sample of a subsurface formation.
  • the method 900 may also include directing a coring bit into the earth, and actuating the coring bit to collect the core sample. Blocks 904 and 906 may be carried out at with two axially separated positions in the coring bit to obtain two different measurements, and the two different measurements may be compared to determine a rate at which the core sample is entering a coring bit.
  • the optical transmission system is described as having one or more optical fibers which could be replaced with waveguides or open channels and an arrangement of mirrors and/or lenses to define the optical path.
  • the optical analysis system can be adapted to other types of drill bits, such as roller cone drill bits. (To examine the formation, the window can be located in a gauge surface of one of the legs for the roller cones. Drilling fluids can be examined by locating the window in a flow- nozzle and/or a junk slot. A comparison of uncontaminated and contaminated fluids may be performed.) It is intended that the claims be interpreted to embrace all such variations and modifications.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (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)
  • Mechanical Engineering (AREA)
  • Investigating Or Analysing Materials By Optical Means (AREA)

Abstract

L'invention porte sur un procédé pour obtenir un échantillon de carotte, lequel procédé met en œuvre le fait de diriger une lumière vers un échantillon de carotte qui est collecté, la réception d'une lumière réfléchie à partir de l'échantillon de carotte, et l'analyse de la lumière réfléchie reçue pour déterminer une ou plusieurs caractéristiques de l'échantillon de carotte et/ou former une image de l'échantillon de carotte. Des caractéristiques comprennent le type de roche, le type d'hydrocarbure, la concentration d'eau, la porosité et la perméabilité. La lumière peut être des infrarouges (IR), de la lumière visible et/ou des ultraviolets (UV). La lumière réfléchie reçue peut traverser un ou plusieurs éléments optiques multidimensionnels (MOE). Des mesures effectuées à deux positions différentes sur l'échantillon de carotte peuvent être utilisées pour déterminer un taux de carottage. Un trépan de carottage décrit comprend un fût pour recevoir un échantillon de carotte, une source de lumière éclairant l'échantillon de carotte lorsqu'il entre dans le fût, un système de détecteur qui reçoit une lumière réfléchie à partir de l'échantillon de carotte, et un système de transmission optique communiquant de la lumière vers l'échantillon de carotte et à partir de celui-ci.
EP11866449.9A 2011-06-02 2011-06-02 Trépans de carottage et de forage à analyseur optique intégré Withdrawn EP2715032A4 (fr)

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2011/038839 WO2012166138A1 (fr) 2011-06-02 2011-06-02 Trépans de carottage et de forage à analyseur optique intégré

Publications (2)

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EP2715032A1 true EP2715032A1 (fr) 2014-04-09
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EP2715032A4 (fr) 2016-03-09
CN103688011A (zh) 2014-03-26
WO2012166138A1 (fr) 2012-12-06
CA2837656A1 (fr) 2012-12-06
CN103688011B (zh) 2016-07-06
AU2011369404A1 (en) 2013-12-05

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