US20110214879A1

US20110214879A1 - Tactile pressure sensing devices and methods for using same

Info

Publication number: US20110214879A1
Application number: US13/039,063
Authority: US
Inventors: Rocco DiFoggio
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2010-03-03
Filing date: 2011-03-02
Publication date: 2011-09-08
Also published as: GB201215432D0; BR112012022095A2; GB2490839A; WO2011109617A3; WO2011109617A2; NO20120948A1

Abstract

A device and related method for conducting a wellbore operation controls a tool by using at least one pressure estimated at a contact between a reaction surface and a contact face associated with the tool. The device may include a contact face and a sensor associated with the contact face. The sensor may be configured to estimate a pressure applied to the contact face.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority from U.S. Provisional Patent Application Ser. No. 61/310,107 filed Mar. 3, 2010, the disclosure of which is incorporated herein by reference in its entirety.

FIELD OF THE DISCLOSURE

This disclosure pertains generally to investigations of underground formations and more particularly to systems and methods for performing one or more tasks in a borehole.

BACKGROUND OF THE DISCLOSURE

To obtain hydrocarbons such as oil and gas, well boreholes are drilled by rotating a drill bit attached at a drill string end. Modern drilling systems generally employ a drill string having a bottomhole assembly (BHA) and a drill bit at an end thereof that is rotated by a drill motor (mud motor) and/or the drill string. A number of downhole devices placed in close proximity to the drill bit measure certain downhole operating parameters associated with the drill string. Such devices typically include sensors for measuring downhole temperature and pressure, and azimuth and inclination measuring devices. Additional downhole instruments, known as measurement-while-drilling (MWD) or logging-while-drilling (LWD) tools, are frequently attached to the drill string to determine formation geology and formation fluid conditions during the drilling operations. After the wellbore is formed, completion tools may be deployed into the wellbore to perform a variety of operations. Some of these tools and devices may, during operation, engage a wellbore wall or some other reaction surface in order to execute one or more assigned tasks.
In one aspect, the present disclosure addresses the need to obtain information relating to the stability or integrity of such reaction surfaces in order to more effectively perform such tasks.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure provides a method for conducting a wellbore operation in a borehole formed in an earthen formation. The method may include controlling a tool in the borehole by using at least one pressure estimated at a contact between a reaction surface and a contact face associated with the tool.
In another aspect, the present disclosure provides an apparatus for conducting one or more wellbore operations. The apparatus may include a carrier conveyable into a well borehole and a tool coupled to the carrier. The tool may include a contact face and a sensor associated with the contact face. The sensor may be configured to estimate a pressure applied to the contact face.
Examples of the more important features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:

FIG. 1 shows a schematic of a downhole tool deployed in a wellbore along a wireline according to one embodiment of the present disclosure;

FIG. 2 schematically illustrates in sectional form a portion of a probe having a contact pressure sensor made according to one embodiment according to the present disclosure;

FIG. 3 schematically illustrates an end view of a probe having a contact pressure sensor made according to one embodiment according to the present disclosure;

FIG. 4 schematically illustrates in sectional form one embodiment of a contact pressure sensor formed in a layer that is disposed on the probe; and

FIG. 5 schematically illustrates one embodiment of a probe having members that can selectively move one or more segments of a contact face of the probe.

DETAILED DESCRIPTION

In aspects, the present disclosure relates to devices and methods for providing enhanced operation of devices that use reaction surfaces. The teachings may be advantageously applied to a variety of systems both in the oil and gas industry and elsewhere. Merely for clarity, certain non-limiting embodiments will be discussed in the context of tools configured for wellbore uses.
FIG. 1 schematically illustrates a wellbore system 10 deployed from a rig 12 into a borehole 14. While a land-based rig 12 is shown, it should be understood that the present disclosure may be applicable to offshore rigs and subsea formations. The wellbore system 10 may include a carrier 16 and a wellbore tool 20. Merely for ease of discussion, the wellbore tool 20 is shown as a fluid analysis tool. It should be understood, however, that the present disclosure may be used in any situation wherein contact pressure may be used to control one or more aspects of a device or process. The fluid analysis tool 20 may include a probe 22 that contacts a borehole wall 24 for extracting formation fluid from a formation 26. Extendable pads or ribs 28 may be used to laterally thrust the probe 22 against the borehole wall 24. The fluid analysis tool 20 may include a pump 30 that pumps formation fluid from formation 26 via the probe 22. Formation fluid travels along a flow line to one or more sample containers 32 or to line 34 from which the formation fluid exits to the borehole 14. A programmable controller may be used to control one or more aspects of the operation of the tool 20. For example, the wellbore system 10 may include a surface controller 40 and/or a downhole controller 42.
Referring now to FIG. 2, there is sectionally shown a portion of the probe 22 having a contact face 50 in contact with the borehole wall 24. The probe 22 may include a rigid support 52 on which a sealing member 54 is disposed. The sealing member 54 may be formed of a material that is pliable at ambient borehole temperatures, e.g., an elastomer. The probe 22 may also include a sensor 56 having a plurality of sensing elements 58. The signals generated by the sensor 56 may be transmitted by a suitable line or signal/power carrier 60 to the controllers 40, 42 (FIG. 1) or to another device. Referring now to FIG. 3, the sensing elements 58 may be distributed at or near the contact face 50 in a manner that enables the sensing of contact pressures at several discrete points or sections around an inlet 62 of the probe 22. In some embodiments, the number of sensing elements 58 and their positioning are selected to identify potential leak paths in the seal formed between the contact face 50 and the wellbore wall 24. While eight sensing elements 58 are shown, it should be understood that greater or fewer number of sensing elements 58 may be employed and that the sensing elements may be arrayed in any configuration suited to measure contact pressure at multiple locations on the contact face 50. For instance, in the non-limiting embodiment shown, the sensing elements 58 are distributed in a grid in order to obtain a pressure distribution map of the contact face 50. The map may, in one aspect, be characterized as including multiple pressure values, with each value being associated with a unique spatial location. The sensor 56 may, therefore, provide in “real-time” pressure values.
Because the magnitude of the contact pressure is a function of the resistance offered by the borehole wall 24, i.e., the reaction surface, the output of the distributed sensing elements 58 may provide an indication of the strength, texture or stability of the borehole wall 24 in physical contact with the sealing member 46 around the inlet 62 of the probe 22. Referring now to FIGS. 2 and 3, during operation, contact pressure may be generated at the contact face 50 as the ribs 28 (FIG. 1) laterally displace the probe 22. Variations in the magnitude of the contact pressures across the face 50 may be evaluated to determine whether a potential leak path may be present in the seal between the probe 22 and the borehole wall 24. For instance, a segment 69 having a contact pressure lower than adjacent segments may indicate a poor physical contact (e.g., a gap) and, therefore, a potential leak path. In another instance, a rugose surface, which may be ill-suited for forming a seal, may include multiple high spots that generate relatively high pressures. These high pressures may cause discernable non-uniformity in a pressure distribution map.
In some non-limiting embodiments, the sensing elements 58 may be embedded in the sealing member 54 as shown in FIG. 2. Referring now to FIG. 4, in other non-limiting embodiments, the sensing elements 58 may be formed in a layer 64 that is disposed on the sealing member 54. In still other embodiments, the layer 64 may be positioned between the support 52 and the sealing member 54. Generally, the sensing elements 58 may be positioned in any location that enables the sensing elements 58 to obtain discrete or segmented contact pressure measurements.
As will be discussed in greater detail below, the signals generated by the sensing elements 58 may be used to estimate the quality of the seal formed between the contact face 50 of the probe 22 and the wellbore wall 24. By quality, it is meant, in one aspect, the amount of a pressure differential that can be generated between the inlet 62 and the wellbore 14 without having fluids or other contaminants enter the inlet 62 from the wellbore 14. This estimation may be performed by personnel at the surface who monitor or assess the signals of the sensor 56. Additionally or alternatively, the sensor signals may be processed and evaluated by the surface controller 40 and/or the downhole controller 42. A number of methodologies may be used to estimate the quality of the seal. For example, one non-limiting methodology may involve simply evaluating whether any output(s) are below a predetermined percentage of a measured maximum output (e.g., below eighty percent of a maximum reading). Another non-limiting methodology may involve determining whether adjacent sensing elements 58 generate outputs that vary more than a preset amount. Still another methodology may evaluate whether, over time, the outputs increase in an expected manner as the probe 22 is pressed against the borehole wall 24. That is, an increasing amount of thrust that does not generate a proportionate increase in contact pressure may indicate instability in the wall. It should be understood that the listed methodologies are only illustrative and that any other evaluation method may be used.
Illustrative modes of operation will be discussed below with reference to FIGS. 1-3. Merely for convenience, the estimation of seal quality will be described as being performed by the surface controller 40. It should be understood, however, that surface personnel and/or the downhole controller 42 may also autonomously or cooperatively perform such an estimation.
Referring now to FIGS. 1 and 2, in one illustrative mode of operation, the fluid sampling tool 20 is positioned adjacent a formation of interest 26. Next, the pad 28 may be activated to thrust the probe 22 against the borehole wall 24. During this time or after the probe 22 has been pressed against the borehole wall 24, the controller 40 receives signals or output from the sensor 56. As shown, the wall area in contact with the probe 22 has sufficient stability to withstand the thrust applied by the probe 22. Thus, the sensing elements 58 may generate output indicating a uniform contact pressure or uniform increase in contact pressure at most or nearly all segments of the outer surface. While some variance may exist in the contact pressure distribution pattern, the controller 40 may determine that the engagement of the probe 22 to borehole wall 24 is adequately stable in order to proceed with fluid sampling. Thus, tool operation in this context is controlled by continuing with the fluid sampling activity using the tool 24.
Unless a good seal is made to the wall of the wellbore, the fluid sampler will only draw in drilling fluid from the wellbore instead of drawing in the intended target fluid, which is the fluid that is contained within the formation rock, such as formation crude oil or formation brine. The first evidence of a good seal is a temporary drop in fluid pressure as one attempts to withdraw fluid from the formation rock. If there is no initial drop in pressure, then the tool is likely only pulling in drilling fluid from the wellbore at the wellbore fluid pressure but no formation fluid.
A good seal is desirable even when one is not collecting fluid samples but only measuring formation fluid pressures. When there is a good seal, the drawdown process leads to an initial drop in fluid pressure followed by a buildup to a pressure close to the formation fluid pressure, which can be extrapolated to a true formation fluid pressure. Fluid pressures measured by this drawdown technique at different depths are used to determine the fluid pressure gradient from which the formation fluid's density can be calculated, which is important information for the petroleum engineers that is used to determine gas-oil and oil-water contacts as well as crude oil density, which correlates to viscosity.
Conventionally, although one can detect that there is not a good seal, one cannot determine why there is not a good seal or what the appropriate remedy should be. One cannot decide whether to try to simply increase the total pressure on the sealing element or whether there is a valley or hill on the surface of the wellbore to which one is trying to seal, which will always prevent a good seal, in which case one should unseat the tool, relocate it to a different spot in the wellbore, and then reseat it at the new location. Also, the inadequate seal may be caused by a defect in the tool; e.g., the sealing element. A pressure sensor array integrated into the sealing element would also show whether a portion of the sealing element has been gouged out so that the tool will never make a good seal even on a smooth wellbore in which case the operator would bring the tool back to the surface to have its sealing element replaced instead of wasting any more rig time trying to get a seal.
A situation where a seal may be inadequate is described with reference to FIGS. 1 and 4. As shown, the probe 22 is pressed against the borehole wall. However, a portion of the wall may include a gap 66, a weakened area, an uneven surface, unconsolidated material, or other seal-inhibiting feature. The sensing element(s) 58 positioned adjacent to a stable surface 68 will generate output(s) indicative of contact pressure at the stable surface 68. The sensing element(s) 58 positioned adjacent to the gap 66, however, will read a relatively lower contact pressure because of the lack of a stable reaction surface. Control of tool operation in this context may involve the controller 40, based on the received outputs, issuing advice or instructions to terminate the fluid sampling activity. Thereafter, the tool 20 may be controlled by moving the tool 20 to another location and the process re-started.
Referring now to FIG. 5, in one non-limiting variant, the probe 22 may include one or more members 70 that are configured to apply segment-specific pressure. The members 70, which act like individually controllable fingers, may be activated to increase the pressure at any location(s) where the controller 40 estimates that there is inadequate contact pressure between the elastomer and the wall of the wellbore. For example, the segment 70 proximate to the gap 66 has been activated to push a portion of the contact face 50 into engagement with the borehole wall 24. The members 70 may be driven hydraulically, electrically, pneumatically, or by some other suitable means. While the members 70 are shown as fingers that pivot about an end to apply pressure, the members 70 may also include pistons, bladders, or other devices that can depress or push a section of the probe 22 toward the borehole wall 24.
It should be understood that the pressure distribution may be one of several factors used by personnel to control a device or conduct a given activity. That is, the contact pressure may be used in conjunction with other measured parameter to estimate a quality of a seal between the probe 22 and the wellbore wall 24. For example, referring to FIGS. 1 and 2, a pressure sensor 72 may be positioned to sense fluid pressure at the inlet 62. During operation of the pump 30, the pressure at the inlet 62 may be monitored. Generally, a satisfactory seal may be indicated by a drop in fluid pressure at the inlet 62 as the pump 30 is operated. If the pressure has not dropped by an expected amount, that information, together with the pressure distribution map, may be used to estimate the quality of the probe-to-borehole wall seal. In still other embodiments, one or more fluid analysis tools may analyze the fluid flowing through the inlet 62. For example, the fluid analysis tool may be configured to detect wellbore fluids or other wellbore contaminations. Again, that information, together with the pressure distribution map, may be used to evaluate the seal between the probe 22 and the borehole wall 24. Thus, in some embodiments, contact pressure may be processed or evaluated with other measured parameters in order to evaluate seal quality and control the fluid sampling tool 20.
Referring now to FIG. 1, it should be appreciated that the teachings of the present disclosure may be applied to a variety of devices and systems other than fluid sampling tools. For example, the pads 28 may be instrumented with sensor(s) for measuring contact pressure. The pads 28 are merely illustrative of force application members that may be used in steering systems for drilling assemblies, centralizers, or stabilizers, and wellbore anchoring devices. Such information may be used to position the pads 28, control the thrust generated by the pads 28, or control some other aspect of the operation of the pads 28. In another example, other devices configured to engage the wellbore wall 24, such as a packer 80, may include one or more contact pressure sensors. The packers 80 are illustrative of wellbore isolation devices that may be expanded or otherwise actuated to engage a wellbore wall 24. The packers 80 may also engage surfaces associated with a wellbore tubular, such as a casing or liner (not shown). Thus, a reaction surface can include surfaces associated with human-made devices as well as a borehole wall.
In some embodiments, the wellbore system 10 may be a drilling system that configured to form the borehole 14 using tools such as a drill bit (not shown). In such embodiments, the carrier 16 may be a coiled tube, casing, liners, drill pipe, etc. In other embodiments, the wellbore system 10 may use a non-rigid carrier. In such arrangements, the carrier 16 may be wirelines, wireline sondes, slickline sondes, e-lines, etc. The term “carrier” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support, or otherwise facilitate the use of another device, device component, combination of devices, media and/or member.
The controller 40, 42 may include an information processor that is in data communication with a data storage medium and a processor memory. The data storage medium may be any standard computer data storage device, such as a USB drive, memory stick, hard disk, removable RAM, EPROMs, EAROMs, flash memories and optical disks, or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage. The data storage medium may store one or more programs that when executed causes information processor to execute the disclosed method(s). Signals indicative of the parameter may be transmitted to a surface controller. These signals may also, or in the alternative, be stored downhole in a data storage device and may also be processed and used downhole for geosteering or for any other suitable downhole purpose. In one example, wired pipe may be used for transmitting information.
From the above, it should be appreciated that the present disclosure provides, in part, devices and methods for conducting a wellbore operation in a borehole formed in an earthen formation. In embodiments, the device may include a carrier conveyable into a well borehole and a tool coupled to the carrier. The tool may include a contact face and a sensor associated with the contact face. The sensor may be configured to estimate a pressure applied to the contact face. The method may include controlling a tool in the borehole by using at least one pressure estimated at a contact between a reaction surface and a contact face associated with the tool. The pressure(s) may be estimated the at least one pressure using a sensor positioned at the contact face. In some embodiments, the sensor estimates a pressure at a plurality of locations on the contact face using a plurality of sensing elements. The controlling may involve adjusting a force applied to the contact face and/or moving the contact face. The reaction surface may be a borehole wall. The pressure data may be used to form a pressure distribution map of the contact face using the estimate pressure. In some applications, the method may involve drawing a fluid from the formation using a probe associated with the tool, wherein the contact face is formed on the probe.
While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.

Claims

1. A method for conducting a wellbore operation in a borehole formed in an earthen formation, comprising:

controlling a tool in the borehole by using at least one pressure estimated at a contact between a reaction surface and a contact face associated with the tool.

2. The method of claim 1 further comprising estimating the at least one pressure using a sensor positioned at the contact face.

3. The method of claim 2 wherein the sensor estimates a pressure at a plurality of locations on the contact face.

4. The method of claim 1, wherein the controlling includes at least one of: (i) adjusting a force applied to the contact face, and (ii) moving the contact face.

5. The method of claim 1, wherein the reaction surface is a borehole wall.

6. The method of claim 1, further comprising forming a pressure distribution map of the contact face using the estimated pressure, wherein the map includes a plurality of estimated pressures.

7. The method of claim 1, further comprising drawing a fluid from the formation using a probe associated with the tool, wherein the contact face is formed on the probe.

8. An apparatus for conducting a wellbore operation, comprising:

a carrier conveyable into a well borehole;

a tool coupled to the carrier, the tool including a contact face; and

a sensor associated with the contact face, the sensor being configured to estimate a pressure applied at the contact face.

9. The apparatus of claim 8, wherein the sensor includes a plurality of sensing elements.

10. The apparatus of claim 9, wherein the tool comprises a probe on which the contact face is formed, the probe including an inlet, wherein the sensing elements are distributed around the inlet.

11. The apparatus of claim 10, wherein the probe includes a sealing element surrounding the inlet, wherein the sensor is in pressure communication with the sealing element, and wherein an outer surface of the sealing element at least partially defines the contact face.

12. The apparatus of claim 8, wherein the sensor is positioned on the contact face.

13. The apparatus of claim 8, further comprising a controller coupled to the sensor, the controller being programmed to control the tool in response to at least one signal generated by the sensor.

14. The apparatus of claim 13, further comprising a plurality of independently operable force application elements positioned on the contact face, and wherein the controller adjusts the force application elements in response to the sensor signals.

15. The apparatus of claim 8 wherein the sensor is formed in a layer coupled to the contact face.