WO2014194051A1

WO2014194051A1 - Wellbore survey using optical fibers

Info

Publication number: WO2014194051A1
Application number: PCT/US2014/039960
Authority: WO
Inventors: Masoud KALANTARI; Jonathan Ryan Prill; Nicholas Ryan Marchand
Original assignee: National Oilwell Varco, L.P.
Priority date: 2013-05-29
Filing date: 2014-05-29
Publication date: 2014-12-04

Abstract

A system and downhole tool for determining shape of a wellbore (1). A downhole tool includes a plurality of parallel optical fiber cores (8). Each of the cores is at least as long as a wellbore that is to be measured using the tool. Each of the cores includes a plurality of parallel optical fibers and each of the optical fibers comprising a Bragg Grating.

Description

WELLBORE SURVEY USING OPTICAL FIBERS

CROSS-REFERENCE TO RELATED APPLICATION

[0001] The present application claims priority to U.S. Provisional Patent Application No. 61/828,540, filed on May 29, 2013 (Attorney Docket No. 1814-74700) entitled "Welbore Realtime Shape evaluation and Wellbore End-Point Localization by Using Multi-Core Fiber Optics," which is hereby incorporated herein by reference in its entirety.

BACKGROUND

[0002] The first Fiber Bragg Grating ("FBG") was proposed by Ken Hill in 1971. FBGs are a special type of fiber optics that has segments of refractive Bragg gratings along the fiber, for example located periodically along the fiber. The Bragg gratings have a different refractive index than the rest of the fiber. Thus, when light travels through the fiber, some wavelengths are transmitted through the Bragg gratings and some reflected back. The wavelength of reflected light is a function of the distance between consecutive reflectors of the gratings. When the distance between consecutive reflectors changes, the wavelength of reflected light changes as well. By measuring the wavelength of reflected light, also called the Bragg wavelength, the distance between the reflectors making the gratings can be found, resulting in a measurement of the elongation of the fiber optics at the particular locations of the gratings. In FBGs, external environment causes a shift in the Bragg wavelength. This means that FBGs can be used as optical fiber sensors.

[0003] The change in the distance between grating reflectors can be induced by either temperature, or strain in the fiber. The relative shift of the Bragg wavelength due to an applied strain and a change in temperature is approximately given by mathematical relationships known in the art. Typically, a relationship involves a coefficient for strain, which is related to a strain- optic coefficient and a stiffness of the optical fiber, and also a coefficient for temperature, which is made up of the thermal expansion coefficient of the optical fiber, as well as a thermo-optic coefficient. Fiber Bragg gratings can then be used as direct sensing elements for strain and temperature.

[0004] FBG sensors can also be used as transduction elements, converting the output of another sensor, which generates a strain or temperature change. For example, FBG gas sensors use an absorbent coating that expands in the presence of a gas, generating a strain which is measurable by the Bragg wavelength. The absorbent material is the sensing element, converting the amount of gas to a strain. The Bragg grating then transduces the strain to the change in wavelength.

[0005] FBGs are widely used as strain, pressure, or temperature sensors in the industry. FBGs are finding uses in instrumentation applications such as seismology, pressure sensors for extremely harsh environments, and as downhole sensors in oil and gas wells for measurement of the effects of external pressure, temperature, seismic vibrations and inline flow measurement. As such, they offer a significant advantage over traditional electronic gauges used for these applications in that they are less sensitive to vibration or heat and consequently are far more reliable. For example, Pat. App. No. GB 2,329,722 and U.S. Pat. 7,512,292 propose systems for measuring the length of a cable lowered in the wellbore using FBGs, and/or for depth or temperature measurements. U.S. Pat 7,900,699 shows the design of a FBG-based flow and pressure sensor, which is connected to a spinner and a mechanism. In U.S. 7,557,339, an optical fiber system is developed to locate the position of an actuator attached to it during tubing or production casing. U.S. Pat. No. 7,322,421 discuses a deployment method for fiber optic into the wellbore in which the strain applied on FBGs that due to the gravity is minimized. In U.S. 7,664,347, the problem of undesired drift source and environment influence is discussed. U.S. 7,245,382, a system to reduce the noise and fluctuations in the input signal for the light source is proposed.

[0006] In 2009, NASA inspired a method to perform three dimensional shape sensing using three core FBGs, for example as shown in U.S. Pat. No. 7,813,599. In this technology, the strain in three FBGs is measured, and then the strain differences in each co-located segments of the three FBGs are calculated. The measured strain differences are input to a set of formulations, called Frenet-Serret Formula, that determine the three dimensional curve of the FBGs. A 3-D display program is developed for showing the shape of the FBGs in real-time. Other related applications of FBGs can also be found in U.S. Pat. No. 7,884,951, showing a FBG based caliper used to measure the radius of the wellbore in different sections, or in U.S. Pat. No. 8,103,135 in which a FBG based system is used to measure the wellbore diameter in different sections, or a tube diameter contacting the wellbore walls.

[0007] Recently, several oil companies are combining the fiber optic technology with their products to take advantages of fiber optic technology. Surgical companies are also integrating fiber optic technology with their surgical robots. This trend is illustrated for example in U.S. Pat. Nos. 6,995,352, 7,245,791, 7,557,339, 7,646,945 7,781,724, 7,896,069, and 8,183,520, as well as in U.S. Pat. Appl. Pub. Nos. 2011/0090486, 2011/0098533, 2011/0119023, and 2011/0202069.

[0008] Despite these efforts, there remains a need for developing new and improved FBGs for the determination of the shape of a wellbore drilled through the Earth's crust, and/or the determination of the wellbore trajectory. SUMMARY

[0009] Those skilled in the art will readily recognize that the present disclosure and its accompanying figures introduce a new design for FBGs suitable for measuring in real-time the trajectory of the wellbore despite severe environmental effects. The design includes a wire line type carrier comprising a plurality of multi-core fibers. A Frenet-Serret set of equations is used to find the wellbore curvature data. A temperature sensor may be used to determine a temperature profile in the wellbore. A sensor fusion technique is used to combine all the curvature data together and increase the accuracy of the measurement.

[0010] The present disclosure and its accompanying figures also introduce methods of localizing the end point of a wellbore, and/or of real-time determination of a wellbore trajectory that utilize the benefits provided by the new design for FBGs.

[0011] The methods and systems of the present disclosure are not sensitive to the applied strain due to gravity to the FBGs, as the strain due to the gravity cancels out automatically in our proposed technique. In addition, the proposed system, based on FBG technology, is immune to electromagnetic interference.

[0012] Some embodiments of the present disclosure are suitable for use in high temperature wells. Unlike other techniques requiring electrical boards to be conveyed downhole, these embodiments allow all of the measurement and electrical devices to be locates at the Earth's surface, making them less sensitive to the high temperature environment encountered in a wellbore.

[0013] In one embodiment, a system for determining shape of a wellbore includes a plurality of parallel optical fibers and surface equipment. Each of the plurality of parallel optical fibers is dimensioned to extend from a surface location along a length of the wellbore, and includes a Bragg Grating. The surface equipment is configured to emit light into an end of each of the optical fibers, and to determine the shape of the wellbore based on the light that is reflected by the Bragg Grating of each of the optical fibers.

[0014] In another embodiment, a downhole tool includes a plurality of parallel optical fiber cores. Each of the cores is at least as long as a wellbore that is to be measured using the tool. Each of the cores includes a plurality of parallel optical fibers and each of the optical fibers comprising a Bragg Grating.

[0015] In a further embodiment, a system for determining shape of a wellbore includes a plurality of wired drill pipes connected end-to-end and a bottom hole assembly coupled to the wired drill pipes. The bottom hole assembly includes a plurality of parallel optical fiber cores, light detectors, and processing circuitry. Each of the parallel optical fiber cores includes a plurality of parallel optical fibers and each of the optical fibers includes a Bragg Grating. The light detectors are coupled to the optical fibers and are configured to detect light reflected by the Bragg gratings. The processing circuitry is coupled to the light detectors. The processing circuitry configured to: generate wellbore shape information based on the light reflected by the Bragg gratings and detected by the light detectors. The processing circuitry is also configured to transmit the shape information to surface equipment via the wired drill pipes.

NOTATION AND NOMENCLATURE

[0016] Certain terms are used throughout the following description and claims to refer to particular system components. As one skilled in the art will appreciate, companies may refer to a component by different names. This document does not intend to distinguish between components that differ in name but not function. In the following discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to... ." Also, the term "couple" or "couples" is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections. The recitation "based on" is intended to mean "based at least in part on." Therefore, if is based on Y, may be based on 7 and any number of additional factors.

BRIEF DESCRIPTION OF THE DRAWINGS

[0017] For a detailed description of exemplary embodiments of the invention, reference will now be made to the figures of the accompanying drawings. The figures are not necessarily to scale, and certain features and certain views of the figures may be shown exaggerated in scale or in schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness.

[0018] FIG. 1 is a view of a wellbore survey system using optical fibers in accordance with aspects of the present disclosure.

[0019] FIGS. 2 and 3 are views of optical fibers shown in the wellbore survey system of FIG. 1.

[0020] FIG. 4 shows a wellbore survey system that uses optical fibers and wired drill pipes in accordance with principles disclosed herein.

DETAILED DESCRIPTION

[0021] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. It is to be fully recognized that the different teachings and components of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results.

[0022] Accurately localizing the end point of the wellbore and accurate wellbore shape evaluation during drilling operation take considerable time, effort, and cost. The present disclosure proposes an optic-based technology to find the wellbore shape and to locate the end point of the wellbore in real-time with less time and effort, while providing accurate results.

[0023] The present disclosure proposes a new arrangement of FBGs for shape sensing that achieves more accurate results with sensor fusion technique. In the proposed system, three multi-core fibers 7a, 7b, and 7c (Figs. 2, 3) are grouped in a wire line type carrier 2 (Figs. 1-3). While three multi-core fibers are shown, the present disclosure is not limited to this number of multi-core fibers. Inner and outer sheaths of armor wires twisted around the multi-core fibers 7a, 7b, and 7c may be provided to carry the tensile stress, as illustrated respectively at 9 and 10 (Figs. 2-3). Therefore, the armor wires may ensure protection of the multi-core fibers from being pulled and disconnected during use in the wellbore 1 (Fig. 1). The wire line carrier 2 may also comprise a filler 11 (Figs. 2, 3) between the multi-core fibers, that may be made of some sort of flexible materials, e.g. rubber type, to protect the multi-core fibers, keep them in place, and to insulate them. Further, one or more electrical conductor(s) 6 (Figs. 2, 3) may be provided in the core of the wire line carrier to supply electricity. For example to a sonde 4 (Fig. 1) disposed at a distal end thereof.

[0024] The multi-core fibers 7a, 7b, and 7c may comprise the same type of FBGs. However, some of the multi-core fibers or additional multicore fibers (not shown) may implement a different type of FBGs. For example one or more multi-core fibers may comprise Tilted Fiber Bragg Gratings ("TFBGs"), in which the gratings are manufactured with a preset angle to the fiber axis. Multi-core fibers including TFBGs can be used to measure the twist of the wire line cable 2 independently of temperature changes. Measurement of cable twist may be useful to improve the accuracy of the wellbore shape.

[0025] To localize the shape of the wellbore 1 , the plurality of long string of multi-core fibers 7a, 7b, and 7c are attached to wire line type carrier 2 to be sent into the wellbore 1 during drilling. Since the total length of the multi-core fibers 7a, 7b, and 7c act as shape sensing sensor, it gives an accurate evaluation of the wellbore shape and the wellbore end-point position. The wire line type carrier 2 is lowered in the wellbore 1 to measure the shape of the wellbore 1. In some cases, it is lowered once at the end of drilling. In other cases, it is lowered periodically and retrieved prior to continuation of drilling. For example, the wire line type carrier 2 may be pumped down in a flow bore of a drill string, and then retrieved with a winch 5 (Fig. 1) during coil tubing or conventional drilling. A light emitter, a spectrometer, and other surface equipment are placed on the rig floor out of the wellbore, for example in logging unit 12 (Fig. 1); and the wire line type carrier 2 is configured to be sent into the wellbore 1 to measure its trajectory. In an alternative, the multi-core fibers 7a, 7b, and 7c may be segmented and the segments embedded into drill pipes. The threaded connections between the drill pipes may be adapted to connect the segments together and transmit light across drill pipes.

[0026] To measure curvatures that are on the order of magnitude of degrees per one hundred feet, or smaller, the multi-core fibers may be provided with FBGs that reflect a bandwidth sufficiently narrow, and a spectrometer sufficiently precise to measure small wavelength shifts. In addition, the spacing between gratings and their refractive index may be designed to magnify and/or change the Bragg wavelength, and thus select a Bragg wavelength adapted to the order of magnitude of the measured curvatures. Light sources of types other than ultra-violet ("UV") can be used within the scope of the present disclosure.

[0027] By using sensor fusion techniques, the three shape curves resulting from the three multi- core fibers 7a, 7b, and 7c are integrated together in order to achieve higher accuracy and less error. In order to eliminate the temperature effect from the FBG readings, a separate temperature sensor, for example located in the sonde 4 shown in Fig. 1, may also be attached to the wire line type carrier 2 to extract the temperature gradient of the wellbore 1. Then, by knowing the temperature at each segment of the wellbore 1 , the temperature effect can be removed from the FBG output by subtracting the temperature effect in FBG equations. The temperature effect may be excluded from the FBG equations by cancelling out from the three collocated gratings change corresponding to temperature.

[0028] The present disclosure contemplates the application of this real-time shape sensing technology for wellbore shape sensing for directional drilling and measuring-while-drilling ("MWD") operation, in order to accurately localize the end point of the wellbore 1 (or the position of a drill bit), and to find the shape and deflection of the wellbore 1. Further, the present disclosure teaches a new data processing algorithm that can be used in conjunction with the new design of FBG based wellbore shape measurement in order to increase the measurement accuracy and decrease the measurement error.

[0029] Because wellbores do not typically have sharp angle changes with small radius, the light in cores 8a, 8b, and 8c (Figs. 2, 3) and in corresponding cores of fibers 7a, 7b, and 7c is not expected to propagate out of the core, giving confidence of high measurement efficiency and accuracy. In addition, a new data processing algorithm involving sensor fusion technique is used to achieve higher accuracy and less error than available prior art methods. Sensor fusion is the combining of sensory data or data derived from sensory data from several sources such that the resulting information is in some sense better than would be possible when these sources were used individually. The term better in this case can mean more accurate, more complete, or more dependable, or refer to the result of an emerging view.

[0030] FIG. 4 shows a wellbore survey system 100 that uses optical fibers and wired drill pipes in accordance with principles disclosed herein. In the system 100, a drilling platform 102 supports a derrick 104 having a traveling block 106 for raising and lowering a drill string 108. A kelly 110 supports the drill string 108 as it is lowered through a rotary table 112. In some embodiments, a top drive is used to rotate the drill string 108 in place of the kelly 110 and the rotary table 112. A drill bit 114 is driven by a downhole motor and/or rotation of the drill string 108. As drill bit 114 rotates, it creates a borehole 116 that passes through various subsurface formations. A pump 120 circulates drilling fluid through a feed pipe 122 to kelly 110, downhole through the interior of drill string 108, through orifices in drill bit 114, back to the surface via the annulus around 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 borehole integrity. [0031] The drill string 108 is made up of various components, including wired drill pipes 118, drill bit 114, and bottom hole assembly (BHA) 126. The wired drill pipes 118 are connected end- to-end form a communication system that extends from the surface to the BHA 126. Each of the wired drill pipes 118 includes a communicative medium (e.g., a coaxial cable, twisted pair, etc.) structurally incorporated or embedded over the length of the pipe 118, and an interface at each end of the pipe for communicating with an adjacent pipe. The communicative medium is connected to each interface. In some embodiments, the interface may include a coil about the circumference of the end of the pipe for forming an inductive connection with the adjacent pipe. The wired drill pipes 118 provide high bandwidth that allows for transfers of large quantities of data at a high transfer rate. Some embodiments of the drill string 108 may include boosters or repeaters interspersed among the wired drill pipes 118 to extend the reach of communication.

[0032] The BHA 126 includes various tools for monitoring the wellbore environment. More particularly, the BHA 126 includes optical fiber shape measurement tool 128. The optical fiber measurement tool 128 includes the multi-core fibers 7a, 7b, and 7c as shown in Figs. 2 and 3. The multi-core fibers 7a, 7b, and 7c each include optical fibers 8a, 8b, and 8c with Bragg gratings as described herein. The optical fiber shape measurement tool 128 also includes a light emitter 136 that provides light signal input to the optical fibers 8a, 8b, and 8c, light detectors 134 that detect light reflected from the Bragg gratings of the optical fibers 8a, 8b, and 8c, and tool control and processing circuitry 132 coupled to the light emitter 136 and the light detectors 134.

[0033] As the optical fiber shape measurement tool 128 traverses the borehole 116, the tool control and processing circuitry 132 processes the output of the light detectors 134 to generate borehole shape information. The processing provided by the tool control and processing circuitry 132 to produce borehole shape information may be similar to the computations provided by the surface equipment of the logging unit 12. In some embodiments, the tool control and processing circuitry 132 may provide measurements representative of the reflected light signals detected by the light detectors 134 at a sufficient rate to allow surface equipment receiving the measurements via the wired drill pipes 118 to determine the shape of the borehole 1 16. In other embodiments, the tool control and processing circuitry 132 determines borehole shape and transmits shape parameters to the surface via the wired drill pipes 118. Equipment at the surface receives the measurements and/or shape information transmitted by the optical fiber shape measurement tool 128 and synchronizes the measurements and/or shape information with the tool depth information to determine the overall shape of the borehole 116.

[0034] In at least some embodiments of the system 100, the optical fiber shape measurement tool 128 is disposed in the drill string 108 at a location other than the BHA 126.

[0035] The above discussion is meant to be illustrative of the principles and various embodiments of the present invention. Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such variations and modifications.

Claims

CLAIMS What is claimed is:

1. A system for determining shape of a wellbore, comprising:

a plurality of parallel optical fibers, each dimensioned to extend from a surface location along a length of the wellbore, and each comprising a Bragg Grating; and;

surface equipment configured to:

emit light into an end of each of the optical fibers; and

determine the shape of the wellbore based on the light that is reflected by the Bragg Grating of each of the optical fibers.

2. The system of claim 1, wherein the plurality of parallel optical fibers comprises at least three parallel multicore fibers, each comprising at least three optical fibers.

3. The system of claim 1, further comprising a wireline carrier in which the plurality of optical fibers is contained, the wireline carrier comprising an armor sheath comprising a plurality of layers of armor twisted about the plurality of optical fibers.

4. The system of claim 1, further comprising an electrical conductor disposed parallel to the plurality of optical fibers.

5. The system of claim 1, wherein at least one of the optical fibers comprises Tilted Fiber Bragg Gratings.

6. The system of claim 1, wherein total length of the plurality of optical fibers operates as a shape sensor for use in determining the shape of the wellbore.

7. The system of claim 1, wherein the Bragg Grating is configured to reflect a bandwidth sufficiently narrow for measurement of deflection of the wellbore on the order of magnitude of less than 10 degrees per one hundred feet.

8. The system of claim 1, wherein the surface equipment configured to combine wellbore shape curves from each of the plurality of optical fibers

9. The system of claim 1, further comprising a temperature sensor disposed at a distal end of the optical fibers; wherein the surface equipment is configured to:

generate a wellbore temperature profile based on temperature measurements provided by the temperature sensor; and

apply the temperature profile to cancel temperature effects from Bragg Grating output of the plurality of optical fibers.

10. The system of claim 1, wherein the surface equipment is to determine location of an endpoint of the wellbore based on the light that is reflected by the Bragg Grating of each of the optical fibers.

11. The system of claim 1, wherein each of the optical fibers comprises a plurality of longitudinal segments and each of the segments is embedded in a drill pipe; wherein each of the drill pipes is configured to connect the segments together across drill pipes and transmit light across drill pipes.

12. A downhole tool, comprising:

a plurality of parallel optical fiber cores, each of the cores at least as long as a wellbore that is to be measured using the tool;

each of the cores comprising a plurality of parallel optical fibers and each of the optical fibers comprising a Bragg Grating.

13. The downhole tool of claim 12, wherein the plurality of parallel optical fiber cores comprises at least three parallel optical fiber cores, and the plurality of parallel optical fibers comprises at least three optical fibers.

14. The downhole tool of claim 12, further comprising a wireline carrier in which the plurality of optical fiber cores is contained, the wireline carrier comprising an armor sheath comprising a plurality of layers of armor twisted about the plurality of optical fiber cores.

15. The downhole tool of claim 12, further comprising an electrical conductor disposed parallel to the plurality of optical fiber cores.

16. The downhole tool of claim 12, wherein at least one of the optical fibers comprises Tilted Fiber Bragg Gratings.

17. The downhole tool of claim 12, wherein total length of the plurality of optical fiber cores operates as a shape sensor for use in determining the shape of the wellbore.

18. The downhole tool of claim 12, wherein the Bragg Grating is configured to reflect a bandwidth sufficiently narrow for measurement of deflection of the wellbore on the order of magnitude of less than 10 degrees per one hundred feet.

19. The downhole tool of claim 12, wherein each of the optical fiber cores comprises a plurality of longitudinal segments and each of the segments is embedded in a drill pipe; wherein each of the drill pipes is configured to connect the segments together across drill pipes and transmit light across drill pipes.

20. A system for determining shape of a wellbore, comprising:

a plurality of wired drill pipes connected end-to-end;

a bottom hole assembly coupled to the wired drill pipes, the bottom hole assembly comprising:

a plurality of parallel optical fiber cores, each of the cores comprising a plurality of parallel optical fibers and each of the optical fibers comprising a Bragg Grating; light detectors coupled to the optical fibers, the light detectors configured to detect light reflected by the Bragg gratings;

processing circuitry coupled to the light detectors, the processing circuitry configured to:

generate wellbore shape information based on the light reflected by the Bragg gratings and detected by the light detectors; and

transmit the shape information to surface equipment via the wired drill pipes.

21. The system of claim 20, wherein the plurality of parallel optical fiber cores comprises at least three parallel optical fiber cores, and the plurality of parallel optical fibers comprises at least three optical fibers.