WO2012166138A1

WO2012166138A1 - Core and drill bits with integrated optical analyzer

Info

Publication number: WO2012166138A1
Application number: PCT/US2011/038839
Authority: WO
Inventors: Gary E. Weaver; Clive D. Menezes
Original assignee: Halliburton Energy Services, Inc.
Priority date: 2011-06-02
Filing date: 2011-06-02
Publication date: 2012-12-06
Also published as: CA2837656A1; AU2011369404A1; CN103688011A; EP2715032A1; EP2715032A4; CN103688011B

Abstract

A disclosed method for obtaining a core sample includes directing light at a core sample being collected, receiving reflected light from the core sample, and analyzing the received reflected light to determine one or more characteristics of the core sample and/or form an image of the core sample. Characteristics include rock type, hydrocarbon type, water concentration, porosity, and permeability. The light may be infrared (IR), visible, and/or ultraviolet (UV). The received reflected light may be passed through one or more multivariate optical elements (MOEs). Measurements made at two different positions on the core sample may be used to determine a coring rate. A described coring bit includes a barrel to receive a core sample, a light source illuminating the core sample as it enters the barrel, a detector system that receives reflected light from the core sample, and an optical transmission system communicating light to and from the core sample.

Description

CORE AND DRILL BITS WITH INTEGRATED OPTICAL ANALYZER

BACKGROUND

Formation coring is well known in the oil and gas industry. In brief, 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.

Inasmuch as possible, 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.

Another issue of concern is that many formations are poorly consolidated or are subject to degradation as the core samples are retrieved to the surface. Sandy soils and gas hydrates are just two examples of such formations. As a core sample is retrieved through a borehole, the sample experiences changes in pressure and temperature which can cause hydrates to sublimate and gases to expand. Such phenomena can destroy the fabric of the core sample before the core sample reaches the surface, making porosity, permeability, and saturation measurements infeasibie. BRIEF DESCRIPTION OF THE DRAWINGS

The following detailed description should be considered in conjunction with the accompanying drawings, in which:

Fig. 1 shows an illustrative drilling system;

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. 4B shows the principles of operation of an alternative 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^rs an illustrative drill bit impact arrester; and

Fig. 9 is a flow diagram for an illustrative coring method.

It is noted that the drawings and detailed description are directed to specific illustrative embodiments of the invention. It should be understood, however, that the illustrated and described embodiments are not intended to limit the disclosure, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the scope of the appended claims.

DETAILED DESCRIPTION

Accordingly, disclosed herein are core bits and drill bits having integrated optical analyzers. 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.

These and other aspects of the disclosed tools and methods are best understood in terms of a suitable usage context. Accordingly, an illustrative drilling system 100 is shown in Fig. 1. A drilling platform 102 is equipped with a derrick 104 that supports a hoist 106 for raising and lowering a drill string 108. The hoist 106 suspends a top drive 110 that is used to rotate the drill string 108 and to lower the drill string 108 through a well head 1 12. Sections of the drill string 108 are connected by threaded connectors 107. Connected to the lower end of the drill string 108 is a drill bit 114. As the drill bit 114 rotates, the drill bit 114 creates a borehole 120 that passes through various formations 122. A pump 116 circulates drilling fluid through a supply pipe 1 18 to the top drive 110, downhole through the interior of the dri ll string 108, through orifices in the drill bit 114, back to the surface via the annulus around the drill string 108, and into a retention pit 124. The drilling fluid transports cuttings from the borehole into the pit 124 and aids in maintaining the integrity of the borehole 120. The drill bit 1 14 is just one piece of a bottom-hole assembly that includes one or more drill collars (thick-walled steel pipe) to provide weight and rigidity to aid the drilling process. Some of these drill collars include logging instruments to gather measurements of various drilling parameters such as position, orientation, weight-on-bit, borehole diameter, etc. 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. In one specific embodiment, 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. In some embodiments, 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. (In some alternative embodiments discussed herein, 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. In the embodiment of Fig. 2, the drill bit 114 includes a cutter assembly 202 attached to an end of an outer tube 200. During operation, the outer tube 200 rotates, turning the cutter assembly 202 about a longitudinal axis 204 of the drill bit 114 and driving the cutter assembly 202 forward along the axis 204. 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. During normal core drilling, 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. As the drill bit 114 cuts an annular space around the core sample, 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. As indicated in Fig. 2, 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. As described in more detail below, 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. In Fig. 3, 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.

In the embodiment of Fig. 3, 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, and 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. In the embodiment of Fig. 4 A, 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. 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. As described above, 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.

As indicated in Fig. 4A, 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. In some embodiments, 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. An embodiment of the detector system 402 including multiple MOEs is described with reference to Fig. 5 below.

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. For example, one MOE may be designed to detect the spectral signature of methane, while another MOE detects the spectral signature of a light hydrocarbon. Yet 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. 7,911,605 to Myrick et al. entitled "Multivariate Optical Elements for Optical Analysis System," and in U.S. Patent Application Publication No. 2010/0265509 by Jones et al. entitled "In Situ Optical Computation Fluid Analysis System and Method," incorporated herein by reference in their entirety, in addition to MOEs, 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.

As previously mentioned, core samples are often obtained to measure formation porosity, permeability, and saturation. 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. To measure these values, the MOEs can be designed to detect water and hydrocarbon signatures, but also to detect the spectral signatures of certain types of rock which are known to be more porous or permeable than other types. Accordingly, the processor analyzes the detector output signals to detect concentrations of the various fluid, types as well as signs of a. spectral match to one of the known rock types. A neural network or other processing technique can then be used to arrive at a quantitative estimate of porosity, permeability, and/or saturation. Even where quantitative estimates are somewhat ambiguous, it should be possible to correlate the optical analyzer measurements with laboratory analysis of the retrieved core. Such a correlation can then be employed as a basis for estimating porosity, permeability, and saturation measurements for those portions of the core sample which have degraded during the retrieval process.

As previously mentioned, 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. Again, as the drill bit 114 is acquiring the core sample 300, the window⁷ 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.

In the embodiment of Fig. 4 A, 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. In this alternative embodiment 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. During operation of the detector system 402, 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.

Various forms of light sensors are contemplated including quantum-effect photodetectors (such as photodiodes, photoresistors, phototransistors, photovoltaic ceils, and photomultiplier tubes) and thermal-effect photodectors (such as pyroelectric detectors, Golay ceils, thermocouples, thermopiles, and thermistors). Most 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. In the embodiment of Fig. 6, 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, and 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. Similarly, a portion of the light 600 striking the core sample 300, reflecting from the core sample 300, and passing through the window 2.12B enters the optical fiber 302D as the light 602. 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. For example, 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.

Accordingly, 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. (Certain details, such as the bit box, the internal chamber, and flow nozzles, are omitted for clarity.) 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. 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.

Advantageously, the average distance between the impact arresters and the formation can be less than 1/32 inch (0.8 millimeter). In the illustrative bit 700, one of these impact arresters 708 is equipped with a diamond or sapphire window 212. In some embodiments, 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. As 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. In the embodiment of Fig. 8, 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. As the drill bit 700 of Fig. 7 turns, 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.

During operation of the drill bit 700 of Fig. 7, 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. In other embodiments, 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. In 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. During a block 906, 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.

Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. For example, 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. As another example, 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.

Claims

CLAIMS WHAT IS CLAIMED IS:

1. A drill bit comprising:

fixed cutting teeth to form a borehole through a formation as the bit rotates;

at least one impact arrestor that rides in a groove formed by the cutting teeth; and an optical analyzer that illuminates the formation through a window in the impact arrestor and analyzes light reflected from the formation.

2. The bit of claim 1 , further comprising at least one optical fiber to communicate light between the window and the optical analyzer.

3. The bit of claim I, wherein the optical analyzer includes a light source, a light sensor, and an optical path from the light source to the light sensor via the window.

4. The bit of claim 3, wherein the optical analyzer includes at least one multivariate optical element (MOE) that intersects the optical path.

5. The bit of claim 3, wherein the optical analyzer includes a filter wheel that successively places different filters in the optical path.

6. The bit of claim 5, wherein at least one of said filters is an MOE.

7. The bit of claim 1, further comprismg position and orientation sensors, wherein the analyzer uses information from the position and orientation sensors to associate reflected light measurements with positions in an image log.

8. The bit of claim I , further comprising a throat that receives a core sample.

9. A coring bit that comprises:

cutting teeth to cut a core sample from a formation as the bit rotates;

a throat that receives the core sample as it is cut from the formation; and

an optical analyzer that illuminates the core sample through a window in the throat and analyzes light reflected from the core sample.

10. The bit of claim 9, further comprising at least one optical fiber to communicate light between the window and the optica] analyzer.

11. The bit of claim 9, wherein the optica! analyzer includes a light source, a light sensor, and an optical path from the light source to the light sensor via the window.

12. The bit of claim 11, wherein the optical analyzer includes at least one multivariate optical element (MOE) that intersects the optical path.

13. The bit of claim 1 1 , wherein the optical analyzer includes a filter wheel that successively places different filters in the optical path.

14. The bit of claim 13, wherein at least one of said filters is an MOE.

15. The bit of claim 9, further comprising position and orientation sensors, wherein the analyzer uses information from the position and orientation sensors to associate reflected light measurements with positions in an image log of the core sample's surface.

16. The bit of claim 15, further comprising a second window through which the analyzer measures reflected light for a second image log.

17. The bit of claim 16, wherein the analyzer compares the image logs to determine a coring rate.

18. The bit of claim 17, wherein the analyzer compares the coring rate to a rate determined from the position sensors.

19. A method for obtaining a core sample, comprising:

directing light at the core sample as the core sample is being collected dovviihole;

receiving at least a portion of the light reflected from the core sample; and

analyzmg the received reflected light to determine at least one characteristic of the core sample.

20. The method of claim 19, wherein said analyzing operation includes filtering the reflected light with a multivariate optical element.

21. The method of claim 19, wherein the at least one characteristic of the core sample includes at least one of the set of characteristics consisting of: rock type, hydrocarbon type, water concentration, porosity, and permeability.

22. The method of claim 19, further comprising: associating reflected light measurements with positions on a surface of the core sample to obtain an image.

23. A drill bit comprising:

teeth to form a borehole through a formation as the bit rotates;

at least one nozzle that passes fluid from an interior flow passage to a region around the teeth;

at least one junk slot that enables the fluid to carry debris away from the teeth; and an optical analyzer that illuminates the fluid through a window in the nozzle or the junk slot and analyzes light reflected from the fluid.

24. The bit of claim 23, wherein at least some portion of the optical analyzer is positioned in a location formerly designated as a nozzle.

25. The bit of claim 23, wherein the optical analyzer compares light from fluid before it exits the bit and after it interacts with the formation.

26. The bit of claim 23, wherein the optical analyzer includes at least one multivariate optical element (MOE).