1. Field of the Disclosure
The disclosure relates generally to obtaining core samples from a formation and drilling wellbores in the formation.
2. Description of the Related Art
Oil wells (also referred to as “wellbores” or “boreholes”) are drilled with a drill string that includes a tubular member having a drilling assembly (also referred to as the “bottomhole assembly” or “BHA”) at an end of the tubular member. To obtain hydrocarbons such as oil and gas, wellbores are drilled by rotating a drill bit attached at a bottom end of the drill string. The drill string may include a coring tool with a coring drill bit (or “coring bit”) at the bottom end of a drilling assembly. The coring bit has a through-hole or mouth of a selected diameter sufficient to enable the core sample to enter into a cylindrical coring barrel inside the drilling assembly (coring inner barrel). One or more sensors may be placed around the core barrel to make certain measurements of the core and of the formation surrounding the wellbore drilled to obtain the core. The length of the core sample that may be obtained is limited to the length of the core barrel, which, in an embodiment, may be 600-feet long or longer. Rotation of the coring inner barrel may cause fracturing of the core sample during drilling, thereby reducing or destroying the core's integrity for measurement. Therefore, it is desirable to detect rotation of and maintain a stationary (or non-rotating) state for the coring inner barrel as it receives the core in order to extract a continuous solid and unbroken core sample.
In one aspect, a coring apparatus is provided, which apparatus in one exemplary embodiment includes a rotatable member coupled to a drill bit configured to drill a core from a formation, a substantially non-rotatable member in the rotatable member configured to receive the core from the formation, and a sensor configured to provide signals relating to rotation between the rotatable member and the non-rotatable member during drilling of the core from the formation, and a circuit configured to process the signals from the sensor for estimating rotation between the rotatable member and the non-rotatable member.
In another aspect, a method of obtaining a core from a formation is provided, which method in one embodiment may include: rotating a drill bit attached to an outer member to obtain the core from a formation; receiving the core in a substantially non-rotating member disposed in the rotating member; obtaining measurements relating to the rotation of the rotating member relative to the substantially non-rotating member using a sensor; determining relative rotation of the rotating member and the substantially non-rotating member using the sensor measurements; and storing information relating to the relative rotation in a suitable storage medium.
Examples of certain features of the apparatus and method disclosed herein are summarized rather broadly in order that the detailed description thereof that follows may be better understood. There are, of course, additional features of the apparatus and methods disclosed hereinafter that will form the subject of the claims appended hereto.
For detailed understanding of the present disclosure, references should be made to the following detailed description, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:
The present disclosure relates to devices and methods for obtaining core samples from earth formations and is described in reference to certain specific embodiments. The concepts and embodiments described herein are susceptible to embodiments of different forms. The drawings show and the written specification describes specific embodiments of the present disclosure for explanation only with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein.
The drilling assembly 120 further may include a variety of sensors and devices, generally designated herein by numeral 160, for taking measurements relating to one or more properties or characteristics, including, but not limited to, core properties, drill bit rotational speed, rate of penetration of the drill bit, rock formation, vibration, stick slip, and whirl. A controller 170 in the drilling assembly 120 and/or the controller 140 at the surface may be configured to process data from downhole sensors, including sensors associated with the coring tool 155 for determining the stability and rotation of the core 165. Additionally, the drilling assembly 120 may include sensors for determining the inclination, depth, and azimuth of the drilling assembly 120 during drilling of the wellbore 110. Such sensors may include multi-axis inclinometers, magnetometers and gyroscopic devices. The controllers 170 and/or 140 also may control the operation of the drilling system and the devices 160. A telemetry unit 178 in the drilling assembly 120 provides two-way communication between downhole devices 160 and the surface controller 140. Any suitable telemetry system may be utilized for the purpose of this disclosure, including, but not limited to, a mud-pulse telemetry, electromagnetic telemetry, acoustic telemetry, and wired-pipe telemetry. The wired-pipe telemetry may include jointed drill pipe sections fitted with data communication links, such as electrical conductors or optical fibers. The data may also be wirelessly transmitted using electromagnetic transmitters and receivers or acoustic transmitters and receivers across pipe joints.
Still referring to
The surface control unit 140 may receive signals from the downhole sensors and devices via a sensor 143 placed in the fluid line 138 as well as from sensors S1, S2, S3, hook load sensors and any other sensors used in the system. The control unit 140 processes such signals according to programmed instructions and displays desired drilling parameters and other information on a display/monitor 142 for use by an operator at the rig site to control the drilling operations. The surface control unit 140 may be a computer-based system that may include a processor 140a, memory 140b for storing data, computer programs, models and algorithms 140c accessible to the processor 140a in the computer, a recorder, such as tape unit for recording data and other peripherals. The surface control unit 140 also may include simulation models for use by the computer to process data according to programmed instructions. The control unit responds to user commands entered through a suitable device, such as a keyboard. The control unit 140 is adapted to activate alarms 144 when certain unsafe or undesirable operating conditions occur.
In an aspect, the rotation measurement apparatus 202 is configured to measure rotation of outer barrel 204 relative to inner barrel 206. In one configuration, the rotation measurement apparatus 202 includes a sensor 218, target 220, target elements 222 and communication link 224. The sensor 218 is configured to sense movement relative to the target 220. In one aspect, the target 220 includes target elements 222, which are used with the sensor 218 to determine rotational motion of the outer barrel 204 relative to the inner barrel 206. In one embodiment, the sensor 218 is embedded in the outer barrel 204 and may be Hall-effect sensor. In one aspect, the target elements 222 may be raised portions or protrusions, such as spaced apart splines on the inner barrel 206. The sensor 218 provides a signal corresponding to each protrusion during rotation of the outer barrel relative to the inner barrel. The signals from the sensor 218 are processed to quantify or determine relative rotation of the outer barrel relative to the inner barrel. The Hall-effect sensor 218 includes a transducer that varies its output voltage in response to changes in magnetic field, where the movement of the sensor 218 relative to the target elements 222 alter the field. Troughs or channels (not shown) may be used instead of protrusions on the inner barrel. Also, any other target shape and size suitable for the Hall-effect sensor 218 may be utilized. In an aspect, the inner barrel 206 and target elements 222 may be made of a conductive material such as steel or an alloy, where the target elements 222 cause a change in the magnetic field to be detected by the Hall-effect sensor 218. In one aspect, the target elements 222 are ridges, splines or raised portions with gaps between the ridges, where the alternating gaps and ridges are detected by the sensor 218. In another embodiment, the target elements 222 and/or the inner barrel 206 may include magnets that affect the magnetic field via rotation, wherein the changes in the field are determined to identify rotation.
In another embodiment, the target elements 222 may be incorporated in a specific pattern and the sensor 218 may be an optical sensor or encoder. The pattern 222 may include alternating stripes of light and dark colors painted on the target 220 or inner barrel 206 that indicate movement of the inner barrel 206 relative to the outer barrel 204. In such an embodiment, the space between the target 220 and sensor 218 is relatively unobstructed to enable the optical sensor 218 to detect movement of the target 220. Therefore, in an embodiment, the drilling fluid is routed around the gap between the sensor 218 and target 220. In another embodiment, the target elements 222 may be radio frequency (RF) tags and the sensor 218 may be an RF tag sensor. In an aspect, the RF tag elements 222 emit signals that indicate the position and/or movement of the inner barrel 206 relative to the sensor 218 and outer barrel 204.
In another embodiment, the target elements 222 may be incorporated in a specific pattern and the sensor 218 may be an optical sensor or encoder. The pattern 222 may be alternating stripes that indicate movement of the inner barrel 206 relative to the outer barrel 204. In another embodiment, the target elements 222 may be splines or ridges and the sensor 218 may be a micro-switch. The micro-switch 218 may be a transducer with a biased roller and/or cam, where the roller maintains contact with the target 220 and emits a signal to indicate when the roller passes over a spline or a ridge. These signals indicate movement of the inner barrel 206 relative to the outer barrel 204. Any other suitable sensor device that provides the relative motion between a rotating member and substantially non-rotating member may be utilized.
As discussed above, the rotation measurement apparatus 202 is configured to measure rotation of the outer barrel 204 relative to inner barrel 206. For example, during a coring operation, the bit 212 and outer barrel 204 rotate at a selected speed, such as 100 RPM to obtain a core from the formation. The inner barrel 206 is configured to remain substantially stationary (non-rotating) to allow the barrel to receive the core and to maintain the core stationary along the radial or lateral direction. By not rotating the inner barrel 206, the core's cylindrical sample from the formation remains attached to the formation, enabling a long (axial length of the cylinder) continuous core sample to be taken. If the inner barrel 206 rotates, the sensor 218 and rotation measurement apparatus 202 will detect a variation from the expected rate of rotation, such as 100 RPM, for example 99 rpm. In the embodiment shown, a control unit 170 or 140 (
In an aspect, the rotation between the inner and outer barrels is detected by a sensor which measures the relative motion between the barrels with or without physical contact between them. In one aspect, the sensing mechanism has a variable gap between the sensor tip (sensing element) and the target to generate the pulse which is amplified and converted into recordable data. The variable gap may be created by slots machined on the inner barrel pieces. The sensing element may be embedded in the outer barrel or placed in a separate sub or device. If relative motion between the barrels varies, the gap between the sensing element and the target varies as a peak or a valley faces the sensing element. The number of slots or splines determines the resolution of the sensor apparatus up to a desired fraction of a rotation or turn. In another aspect, the sensor mechanism may include a tactile sensing element, such as a roller or an arm, wherein the signals are generated as the roller or arm moves over the ridges. The signals from the sensor may be processed by controller 170 and/or 140.
Thus, in one aspect, a coring apparatus is provided, which apparatus in one embodiment includes an outer rotating member coupled to a drill bit for drilling a core, an inner substantially non-rotating member in the outer member and configured to receive a core from a formation, and a sensor apparatus configured to measure rotation of the inner substantially non-rotating member when the rotating member is rotating to drill the core. In one aspect, the sensor apparatus includes a sensor or sensing element and a target. In one aspect, the sensor may be a Hall-effect sensor, a radio frequency sensor, an optical sensor, a micro-switch, or any other suitable sensor. In another aspect, the target may be protrusions, such as splines, channels or recesses, such as grooves, radio frequency tags, stripe patterns, color variations, magnetic markers, or any combination thereof. In one aspect, the target may be located on the substantially non-rotating member and the sensor on the rotating member or vice versa. In another aspect, the coring apparatus further includes a communication link for transmitting signals from the sensor to a controller. The communication link may include one of: a split ring connection associated with the substantially non-rotating member, a short-hop acoustic sensor, a direct connection between the sensor and a controller in a drilling assembly coupled to the coring apparatus.
In another aspect, a method of obtaining a core sample is provided, which method, in one embodiment may include: rotating an outer member with a coring bit to obtain the core from a formation; receiving the core in a substantially non-rotating member disposed in the rotating member; and determining rotation of the substantially non-rotating member using a sensor apparatus during rotation of the rotating member. The method may further include taking a corrective action when the rotation of the substantially non-rotating member is outside a selected limit. In one aspect, the corrective action may include one or more of altering drill bit rotation, altering weight-on-bit, stop receiving the core, retrieving the core; and altering inclination. In aspects, the sensor apparatus may include a sensor and a target. In one aspect, the sensor may be one of a Hall-effect sensor, a radio frequency sensor, an optical sensor, a micro-switch, or any other suitable sensor. In another aspect, the target may be protrusions, such as splines, channels or recesses, such as grooves, radio frequency tags, color variations, and magnetic elements.
The foregoing description is directed to particular embodiments of the present disclosure for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope of the disclosure and the following claims.
This application claims priority from the U.S. Provisional Patent Application having the Ser. No. 61/324,194 filed Apr. 14, 2010.
Number | Date | Country | |
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61324194 | Apr 2010 | US |