US20090151935A1 - System and method for detecting movement in well equipment - Google Patents

System and method for detecting movement in well equipment Download PDF

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Publication number
US20090151935A1
US20090151935A1 US12/173,546 US17354608A US2009151935A1 US 20090151935 A1 US20090151935 A1 US 20090151935A1 US 17354608 A US17354608 A US 17354608A US 2009151935 A1 US2009151935 A1 US 2009151935A1
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sensor
apparatus
reservoir
well
connection mechanism
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Abandoned
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US12/173,546
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John R. Lovell
Stuart MacKay
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Schlumberger Technology Corp
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Schlumberger Technology Corp
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Priority to US12/173,546 priority patent/US20090151935A1/en
Assigned to SCHLUMBERGER TECHNOLOGY CORPORATION reassignment SCHLUMBERGER TECHNOLOGY CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: MACKAY, STUART, LOVELL, JOHN R.
Publication of US20090151935A1 publication Critical patent/US20090151935A1/en
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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods ; Cables; Casings; Tubings
    • E21B17/02Couplings; joints
    • E21B17/04Couplings; joints between rod or the like and bit or between rod and rod or the like
    • E21B17/07Telescoping joints for varying drill string lengths; Shock absorbers
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/0006Measuring stresses in a well bore pipe string or casing
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/01Devices for supporting measuring instruments on a drill pipe, rod or wireline ; Protecting measuring instruments in boreholes against heat, shock, pressure or the like

Abstract

An apparatus for use in a well for indicating movement of a reservoir. The apparatus may include first and second equipment assemblies connected by a telescoping connection mechanism. A sensor assembly may be provided and configured to detect relative movement of at least a portion of the telescoping connection mechanism. The relative movement of at least a portion of the telescoping mechanism may interpreted so as to correlate to the compaction or expansion of the reservoir.

Description

    RELATED APPLICATIONS
  • The following is based on and claims the benefit of priority under 35 U.S.C. §119 to U.S. Provisional Patent Application Ser. No. 61/013,542 entitled, “METHOD AND APPARATUS TO MEASURE RESERVOIR COMPACTION,” filed on Dec. 13, 2007.
  • TECHNICAL FIELD
  • The invention relates to measuring movement in well equipment for measuring reservoir compaction.
  • BACKGROUND
  • One or more wellbores can be drilled through an earth formation to a reservoir that may contain hydrocarbons or other types of fluid (e.g. water). Completion equipment can then be provided into the one or more wellbores. The completion equipment can be used for extracting fluid from the reservoir and producing the fluid to the earth surface.
  • As fluid is extracted from the reservoir, reservoir compaction may occur. As fluid is extracted, the reservoir pressure decreases in certain zones of the reservoir, in some cases causing a loss of consolidation and overall compaction of the reservoir. Reservoir compaction is particularly a problem in high permeability reservoirs, or low porosity reservoirs, for example.
  • Compaction, or other movement of a reservoir can cause deformation of well equipment, such as casing or tubing provided in the wellbore(s), and can lead to failure of such well equipment.
  • In some cases, well operators attempt to predict the amount of movement that may occur as a result of production from the reservoir. The operators then attempt to modify well equipment to accommodate such movement. However, modifying well equipment designed to accommodate predicted movement of the reservoir is relatively expensive. Also, effective well equipment designed to account for reservoir compaction, for example, requires an accurate prediction of the potential degree of reservoir compaction, which may not be economically feasible or possible.
  • SUMMARY
  • In general, according to an illustrative embodiment of the present invention, an apparatus for use in a well that extends to a reservoir includes first and second equipment assemblies, and a telescoping connection mechanism between the first and second equipment assemblies. A sensor detects movement in the telescoping connection mechanism to enable measurement of reservoir compaction.
  • Other or alternative features will become apparent from the following description, from the drawings, and from the claims.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • FIG. 1 illustrates example well equipment disposed in a wellbore having first and second equipment assemblies connected by a telescoping connection mechanism and a sensor to detect movement of the telescoping connection mechanism, according to an embodiment of the present invention.
  • FIG. 2 illustrates a telescoping connection mechanism and an associated sensor assembly, according to an embodiment of the present invention.
  • FIG. 3 illustrates a schematic showing the use of an inductive coupler with a system incorporated in an embodiment of the present invention.
  • DETAILED DESCRIPTION
  • In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments are possible.
  • As used here, the terms “above” and “below”; “up” and “down”; “upper” and “lower”; “upwardly” and “downwardly”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or diagonal relationship as appropriate.
  • In accordance with some exemplary embodiments of the present invention, a system for use in a well that extends to a reservoir may include well equipment having multiple assemblies connected by a telescoping connection mechanism. A telescoping connection mechanism may be configured to allow for relative axial movement of the first and second equipment assemblies (e.g., along the axial direction of the equipment assemblies and the wellbore). Also, a sensor assembly may be associated with the telescoping connection mechanism in order to detect movement in the telescoping connection mechanism in order to estimate or measure reservoir compaction. Reservoir compaction refers to one or more zones of the reservoir collapsing due to fluid loss and the associated loss of pressure, for example, resulting in an overall reduction of the length of the wellbore extending through the collapsed zones.
  • The sensor assembly can include one or more sensors, where one sensor is used for detecting movement in the well equipment, while other sensors can measure other properties associated with the wellbore and/or reservoir. As discussed further below, measurements made by such other sensors can also be used as an independent indication or verification of reservoir compaction.
  • FIG. 1 illustrates an exemplary arrangement that includes well equipment installed in a wellbore 100 and having a first assembly 102 and a second assembly 104 interconnected by a telescoping connection mechanism 106. In one example, the well equipment assembly 102 may comprise a first casing segment, and the well equipment assembly 104 may comprise a second casing segment. A “casing” is a structure, normally formed of metal, which may line the walls of the wellbore. The telescoping connection mechanism 106 allows for relative axial movement of the first and second casing segments 102 and 104. In other examples, other forms of tubular structures (e.g., pipes, tubing, etc.) can be connected to the telescoping connection mechanism 106. Generally, a “telescoping connection mechanism” refers to any mechanism that interconnects two members while allowing relative axial movement of the two members. For example, the telescoping connection mechanism can be a contracting joint or an expansion joint.
  • The wellbore 100 depicted in FIG. 1 extends to a reservoir 108 that may contain a desirable fluid such as hydrocarbon, fresh water, and so forth. Production equipment 103 can be provided inside the wellbore to extract the fluid from the reservoir 108 as part of a production operation.
  • The first and second casing segments 102, 104 may be connected or coupled to the formation adjacent to the wellbore. If reservoir compaction occurs, one or both of the casing segments 102, 104 may shift as a result of the compaction. This shifting can cause the casing segments 102, 104 to move axially relative to each other at the telescoping connection mechanism 106. Although reservoir compaction is typically described as casing segment 102 moving closer to casing segment 104, embodiments of the current invention may also encompass relative axial movement in which the casing segments 102, 104 move away from each other, as will be readily appreciated by those of skill in the art.
  • In accordance with some embodiments of the present invention, a sensor assembly 110 may be associated with the telescoping connection mechanism 106. The sensor assembly 110 may be connected to a communications link 112 that extends to well surface equipment 116. The communications link 112 can include an electrical cable, a fiber optic cable, or some other type of link (e.g., wireless link, such as an acoustic link, pressure pulse link, electromagnetic link, etc.). The communications link 112 may pass through the wellhead 114 in order to connect to a controller 118 provided at the well surface.
  • The controller 118 (which can be implemented with a computer, for example) may be configured to receive measurement data from the sensor assembly 110, and to process the measurement data to provide an indication regarding one or more properties of the wellbore 100 and reservoir 108. The one or more properties can include indications of whether the reservoir 108 has experienced compaction, and the extent of such compaction, for example. Other well or reservoir properties that can be indicated by the controller 118 may include pressure, temperature, and reservoir resistivity, among others.
  • In the example of FIG. 1, the controller 118 may include processing software 120 executable on one or more central processing units CPU(s) 122, which is (are) connected to storage 124. The storage 124 can be used to store measurement data as well as instructions contained in the form of software 120.
  • An example of the telescoping connection mechanism 106 is depicted in FIG. 2. The telescoping connection mechanism 106 may include a first connection segment 202 (which is connected to the first casing segment 102), and a second connection segment 204 (which is connected to the second casing segment 104). Note that in some implementations, the second casing segment 104 along with the second connection segment 204 (e.g., as part of a lower completion assembly) can be deployed into the wellbore first, followed later by deployment of the first casing segment 102 along with the first connection segment 202 (e.g., as part of an upper completion assembly). In such multi-part deployment, the later deployed first connection segment 202 may be landed with the previously installed second connection segment 204.
  • Alternatively, the first casing segment 102, second casing segment 104, and the telescoping connection mechanism 106 can be deployed into the wellbore together.
  • The second connection segment 204 has a portion 205 of reduced diameter relative to the first connection segment 202. As a result, the reduced diameter portion 205 can move axially inside of the first connection segment 202. Each of the first and second connection segments 202 and 204 may be configured to be generally tubular in shape, so that the reduced diameter portion 205 may be substantially concentrically arranged inside (and moveable with respect to) the first connection segment 202.
  • In some implementations, it may be desirable to run a cable or control line (arranged outside the casing segments 102 and 104) through the telescoping connection mechanism 106. To do so, such a cable or control line can be wound around the outside of the connection segments 202 and 204. In other cases, the communications link may be run along an interior bore or within portions of the casing segments 102, 104 (e.g., such as along the exterior of production tubing, among other methods).
  • As further depicted in FIG. 2, a motion or position detector 206, which is part of the sensor assembly 110 of FIG. 1, may be provided as a part of the telescoping connection mechanism 106. The motion detector 206 may be configured with a radial protrusion 208 (e.g., a mechanical probe member) that engages with a slanted surface 210 provided by a profile feature 212 (e.g., a conical shape, cam surface, or some other shape) inside the first connection segment 202.
  • A biasing element 214, such as a spring, may be provided to push the first connection segment 202 away from the second connection segment 204. However, due to compaction of the surrounding reservoir, the first and second connection members 202 and 204 may overcome the biasing force and be pushed towards each other, or in some cases be pushed further away from each other. Assuming for the purpose of description that the second connection segment 204 (and the second casing segment 104) is fixed in position, then relative movement of the first and second connection segments 202 and 204 will cause relative axial movement of the first connection segment 202, for example. Accordingly, the radial protrusion 208 of the motion detector 206 will move along or across the slanted surface 210 of the profile feature 212. Movement along the slanted surface 210 by the radial protrusion 208 results in radial movement (i.e., displacement) of the radial protrusion 208. The angle of the slanted surface 210 may function to correlate a large axial movement to a relatively limited radial movement.
  • As depicted in FIG. 2, if the radial protrusion 208 were to move downwardly relative to the first connection segment 202 (e.g., when the first connection segment 202 is moving away from the second connection segment 204), then the radial protrusion 208 will be pushed radially inwardly by the slanted surface 210. On the other hand, if the radial protrusion 208 were to move upwardly relative to the first connection segment 202 (e.g., when the first connection segment 202 is moving toward the second connection segment 204), then the radial protrusion 208 will move radially outwardly.
  • The motion detector 206 may be configured to detect differences in the radial position of the radial protrusion 208, and to communicate the extent of such radial movement over the communications link 112 (FIG. 1) to the earth surface controller 118 for processing.
  • In another embodiment, the profile feature 112 may be present on the second connection segment 204 and the radial protrusion 208 and motion detector 206 can be provided on the first connection segment 202. In still other embodiments, a motion detector similar to motion detector 206 may directly engage with the first connection segment 202 so that relative movement between the first and second connection segments 202, 204 can be detected.
  • The motion detector 206 can provide continuous measurement of movement, corresponding to continuous movement of the radial protrusion 208 relative to the slanted surface 210. Such detected continuous movement can be reported continuously to the earth surface controller 118. Alternatively, instead of continuous measurement data, the motion detector 206 can report discrete movement measurements to the controller 118. Even further alternatively, the motion detector 206 may be interrogated either periodically or continuously to report the current position of the radial protrusion 208 or change in position of the radial protrusion 208.
  • Note that the sensor assembly 110 can include one or more other sensors, such as 216, 218, 220, and so forth. Some of these sensors may be provided as part of the telescoping connection mechanism 106, while other sensors may be provided apart from the connection mechanism 106. The sensors can include pressure sensors, temperature sensors, and resistivity sensors, among others.
  • The motion detector 206 of FIG. 2 functions effectively as a position sensor that is used to detect changes in the position of a mechanical component, in this case the first connection segment 202. Through the use of a profile feature 212 comprising a slanted surface 210, for example, a relatively small change in radial position may be correlated to a relatively large change in axial position.
  • In a different implementation, a position sensor can be implemented using an optical, resistive, electrical, electrostatic, or magnetic mechanism. For example, a position sensor can include an optical detector that uses the Faraday effect, a photo-activated ratio detector, a resistive contacting sensor, an inductively coupled ratio detector, a variable reluctance device, a capacitively coupled ratio detector, a radio wave directional comparator, or an electrostatic ratio detector, among others.
  • An optical detector can use a position sensing detector to determine the position of an optical probe light that is incident upon a surface of the moveable device. The probe light can be directed to an optically reflective surface that is attached to the moveable member. The laser beam is reflected from the optically reflective surface. The optical detector may be constructed using photodetectors, such as photo-diodes or PIN-diodes, to detect the reflected laser beam.
  • A capacitance-based position sensor uses a variable capacitor having a value that varies with relative position of a pair of objects. In such systems, the relative position of the objects can be determined by measuring the capacitance.
  • A magnetic sensor to detect motion typically relies upon permanent magnets to detect the presence or absence of a magnetically permeable object within a certain predefined detection zone relative to the sensor. As one example, the magnetic sensor can be a Hall effect sensor. A Hall effect occurs when a current-carrying conductor is placed into a magnetic field, where a voltage is generated that is perpendicular to both the current and the field. Alternatively, the magnetic sensor can include a magnetoresistive sensor, which uses a magnetoresistive effect to detect a magnetic field. Relative movement of members can be detected based on measured magnetic fields.
  • The other sensors used to measure other properties can provide additional information to allow for more accurate detection of whether reservoir compaction has occurred. For example, temperature measurement can be used to provide an indication of compaction, since as pressure within a zone of the reservoir lowers, the granular components within the reservoir are forced into closer contact and may ultimately be fused together. Such action lowers the permeability of the zone and may result in a decrease of flow from that zone. Reduced flow will cause a reduction in temperature, which is an indication of possible reservoir compaction. This data in combination with the position sensor used to detect relative movement of different segments of well equipment can be used to confirm that reservoir compaction has occurred.
  • Note that another possible application of the sensor that is associated with the telescoping connection mechanism 106 is that the sensor assembly 110 can provide an indication that the two different segments of the well equipment have successfully landed into the correct position.
  • In implementations where the first equipment segment and the second equipment segment are deployed at different times, it may be difficult to provide a wired connection from a sensor of the sensor assembly 110 to the earth surface. In such implementations, as depicted in FIG. 3, an inductive coupler mechanism 302 can be provided. A sensor 300, which can be part of the sensor assembly 110 of FIG. 1, may be connected to a first inductive coupler portion 304, which is positioned proximate a second inductive coupler portion 306 when the upper well equipment segment is landed with the lower well equipment segment. In one embodiment, the second inductive coupler portion 306 can be a female inductive coupler portion, while the first inductive coupler portion 304 may be a male inductive coupler portion. When positioned proximate to each other, the inductive coupler portions 304 and 306 may be configured to communicate both power and data such that the sensor 300 can be powered using power provided over the link 112. Further, measurement data of the sensor 300 can be communicated through the inductive coupler 302 to the link 112 for communication to the surface.
  • Alternatively, instead of using an inductive coupler, acoustic telemetry or electromagnetic (EM) telemetry can be used.
  • While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations there from. It is intended that the appended claims cover such modifications and variations as fall within the true spirit and scope of the invention.

Claims (21)

1. An apparatus for use in a well that extends to a reservoir, comprising:
a first equipment assembly;
a second equipment assembly;
a telescoping connection mechanism between the first and second equipment assemblies; and
a sensor assembly to detect movement in at least a portion of the telescoping connection mechanism.
2. The apparatus of claim 1, further comprising a controller configured to interpret measurement data from the sensor assembly and to indicate compaction of the reservoir in response to the measurement data.
3. The apparatus of claim 1, wherein the telescoping connection mechanism has a first segment and a second segment arranged within the first segment, wherein the first and second segments are axially moveable with respect to each other.
4. The apparatus of claim 1, wherein the first equipment assembly comprises a first casing segment to line the well, and the second equipment assembly comprises a second casing segment to line the well, wherein the first and second casing segments are interconnected by the telescoping connection mechanism.
5. The apparatus of claim 1, wherein the sensor assembly comprises a position sensor configured to provide substantially continuous measurement of axial movement of the at least a portion of the telescoping connection mechanism.
6. The apparatus of claim 1, wherein the sensor assembly comprises a position sensor configured to provide discrete measurements indicating axial movement of the at least a portion of the telescoping connection mechanism.
7. The apparatus of claim 1, further comprising production equipment to produce fluid from the reservoir.
8. The apparatus of claim 1, wherein the sensor assembly includes a position sensor configured to detect relative movement between the first and second equipment assemblies.
9. The apparatus of claim 8, wherein the position sensor includes a probe member translatably engaged with a profile surface provided in the telescoping connection mechanism, wherein the position sensor detects movement in the at least a portion of the telescoping connection mechanism based on the relative motion of the probe member and the profile surface.
10. The apparatus of claim 9, wherein the probe member comprises a radial protrusion, and wherein relative motion of the radial protrusion and the profile surface is reported by the position sensor as a radial displacement.
11. The apparatus of claim 8, wherein the position sensor includes one of an optical, resistive, electrical, electrostatic, or magnetic sensor
12. The apparatus of claim 1, wherein the sensor assembly is configured to provide an indication that the first and second completion assemblies have successfully landed with respect to each other.
13. The apparatus of claim 1, wherein the sensor assembly is configured to further provide an indication of one or more properties associated with the well or reservoir.
14. The apparatus of claim 13, wherein the one or more properties include pressure, temperature, or resistivity.
15. A method comprising:
positioning first and second well equipment assemblies in a well;
interconnecting the first and second well equipment assemblies using a telescoping connection mechanism;
detecting relative movement between the first and second well assemblies using a sensor assembly; and
determining an indication of reservoir compaction correlating to the relative movement detected by the sensor assembly,
16. The method of claim 15, wherein positioning the first and second well equipment assemblies comprises positioning first and second casing segments that line the well.
17. The method of claim 15, wherein determining the indication of reservoir compaction comprises:
communicating to a controller the relative movement detected by the sensor;
communicating to the controller other measurement data from the sensor assembly;
interpreting the relative movement and the other measurement data communicated to the controller to provide the indication of reservoir compaction.
18. The method of claim 17, wherein the other measurement data is selected from pressure and temperature of the reservoir.
19. The method of claim 15, wherein detecting the relative movement using the sensor assembly comprises using one of a mechanical position sensor, an optical sensor, a resistive sensor, an electrical sensor, an electrostatic sensor, or a magnetic sensor.
20. The method of claim 15, further comprising communicating relative movement from the sensor assembly to a surface controller through a wireless mechanism.
21. The method of claim 20, wherein communicating the measurement data from the sensor assembly to the surface controller through the wireless mechanism comprises communicating through one of an inductive coupler, an acoustic telemetry mechanism, or an electromagnetic telemetry mechanism.
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US20090302852A1 (en) * 2008-06-05 2009-12-10 Cyrille Levesque Measuring casing attenuation coefficient for electro-magnetics measurements
US20100288510A1 (en) * 2007-10-31 2010-11-18 Scott Pattillo Object manoeuvring apparatus
CN103061746A (en) * 2013-01-08 2013-04-24 中国石油天然气集团公司 Whole-course online stress detection device for distributed optical fiber cables in downhole casing strings in oil and gas wells
US20130188168A1 (en) * 2012-01-20 2013-07-25 Arthur H. Hartog Fiber optic formation dimensional change monitoring
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US10018033B2 (en) 2014-11-03 2018-07-10 Quartzdyne, Inc. Downhole distributed sensor arrays for measuring at least one of pressure and temperature, downhole distributed sensor arrays including at least one weld joint, and methods of forming sensors arrays for downhole use including welding
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