This application is a U.S. National Stage of PCT/US2013/040076 filed on May 8, 2013.
The present disclosure relates to systems, assemblies, and methods for conducting electrical power to and through downhole tools attached to a drill string.
Progressing cavity motors, also known as Moineau-type motors having a rotor that rotates within a stator using pressurized drilling fluid, have been used in wellbore drilling applications for many years. Some Moineau-type pumps and motors used in wellbore drilling include stators which have a polymer lining applied to the bore of the housing. Pressurized drilling fluid (e.g., drilling mud) is typically driven into the motor and into a cavity between the rotor and the stator lining, which generates rotation of the rotor and a resulting torque can be produced. The resulting torque is typically used to drive a working tool, such as a drill bit, to cut material.
Referring to
In various implementations, the drill string includes a Moineau motor and the tool string 40 includes equipment that uses electrical power to operate (e.g., motors), equipment that is configured to receive electrical signals (e.g., actuators), and/or equipment that is configured to transmit electrical signals (e.g., sensors) to and/or from electrical equipment 55 located at the surface 12. The electrical equipment 55 is electrically connected to the drill string 20 by at least one electrical conductor 57. Rotation of the drill string 20 and components within the drill string 20, as well as the harsh environment of the wellbore 60, can lead to breakage of conventional electrical conductors. Such breakage results in additional work and expense needed to identify the location of the fault, to retrieve the corresponding section of the drill string, and to repair the damage, in addition to the costs associated with the resulting downtime
Progressing cavity motors, such as those used in downhole drilling and pump assemblies, typically include a stator defining cavity and a rotor that is sized and configured to rotate within the cavity when pressurized fluid is applied to the cavity.
The rotor 122 is operatively positioned in the cavity 134 to cooperate with the stator lobes 124. Applying fluid pressure to the cavity 134 typically causes the rotor 122 to rotate within the stator 120 in cooperation with the lobes 124. For example, referring to
During a drilling operation, the drilling fluid 90 is pumped down the interior of the drill string 20 (shown broken away) attached to downhole drilling motor 100. The drilling fluid 90 enters cavity 134 having a pressure that is imposed on the drilling fluid by pumps (e.g., pumps at the surface). The pressurized drilling fluid entering cavity 134, in cooperation with the geometry of the stator 120 and the rotor 122, causes the rotor 122 to turn to allow the drilling fluid 90 to pass through the motor 100. The drilling fluid 90 subsequently exits through ports (e.g., jets) in the drill bit 50 and travels upward through an annulus 130 between the drill string 20 and the wellbore 60 and is received at the surface where it is captured and pumped down the drill string 20 again.
These downhole drilling motors fall into a general category referred to as Moineau-type motors. Some conventional Moineau-type pumps and motors include stators that have stator contact surface formed of a rubber or polymer material bonded to the steel housing. However, in the dynamic loading conditions typically involved in downhole drilling applications, substantial heat can be generated in the stator and the rotor. Since rubber is generally not a good heat conductor, thermal energy is typically accumulated in the components that are made of rubber (e.g., the stator). This thermal energy accumulation can lead to thermal degradation and, therefore, can lead to damage of the rubber components and to separation of the rubber components
Additionally, in some cases, the drilling fluid to be pumped through the motor is a material that includes hydrocarbons. For example, oil-based or diesel-based drilling fluids can be used which are known to typically deteriorate rubber. Such deterioration can be exacerbated by the accumulation of thermal energy. Water and water based fluids can present a problem for rubber components in drilling applications.
For optimum performance of the drilling motor, there is typically a certain required mating fit (e.g., clearance or interference) between the rubber parts of the stator and the rotor. When the rubber swells, not only the efficiency of the motor is affected but also the rubber is susceptible to damage because of reduced clearance or increased interference between the rotor and the stator.
Contact between the stator and the rotor during use causes these components to wear (i.e., the rubber portion of the stator or the rotor), which results in the mating fit between the stator and the rotor to change. In some cases, the rotor or the stator can absorb components of the drilling fluid and swell, which can result in the clearance getting smaller, causing portions of the rotor or stator to wear and break off. This is generally known as chunking. In some cases, the chunking of the material can result in significant pressure loss so that the power unit is no longer able to produce suitable power levels to continue the drilling operation. Additionally or alternatively, in some cases, chemical components in the drilling fluid used can degrade the rotor or the stator and cause the mating fit between them to change. Since the efficient operation of the power unit typically depends on the desired mating fit (e.g., a small amount of clearance or interference), the stator and/or the rotor can be adjusted during equipment maintenance operations at surface to maintain the desired spacing as these components wear during use.
In some implementations, the tool string 40 includes electrical elements such as motors, actuators and sensors that are in electrical communication with electrical equipment 55 located at the surface 12. The previously discussed downhole conditions can be highly adverse to conventional electrical conductors, such as insulated wires, as such conductors may interfere with the mechanical operation of the drill string 20 or may be susceptible to breakage, erosion, corrosion, or other damage when exposed to the conditions experienced during drilling operations. In order to provide power to such electrical elements, the drill string 20 and/or elements of the tool string 40 include electrically conductive elements that will be discussed in the descriptions of
In some implementations the insulated conductors disclosed herein may be used to pass one or more electrical conductors through housings and around drive shafts of other downhole drilling tools such as RSS steerable tools, turbines, anti-stall tools and downhole electric power generators. In other implementations, the insulated conductors may be passed through downhole reciprocating tools such as jars and anti-stall tools.
In general, when used with components such as the bores of downhole motor stator housings, the insulated conductive layer 320 can take the form of a circumferential layer, a semi circumferential layer, a thin straight strip, a spiral strip, or any other appropriate conductive layer which is insulated, geometrically unobtrusive (e.g., thin in wall section, with good adhesion), and does not negatively affect stator elastomer bonding or geometry integrity.
The stator 300 includes a tubular housing 310 which is typically formed of steel. The insulated conductive layer 320 is included substantially adjacent to an inner surface of the tubular housing 310. The insulated conductive layer 320 may be formed as a circumferential layer, a semi circumferential layer, a thin straight strip, a spiral strip, or any other appropriate conductive layer. In some implementations, the insulated conductive layer 320 may conform to the geometry of the inner surface of the tubular housing 310.
Referring now to
In some embodiments, the insulating sub-layer 324b can be a protective layer provided radially between the conductive sub-layer 322 and the bore of the tubular stator 300. The insulating sub-layer 324b can protect the conductive sub-layer 322 from the erosive and abrasive conditions that may be present within the bore, e.g., wear from contact with a rotor or shaft, wear and erosion from mud or other fluid flows, chemical degradation due to substances carried by drilling mud or fluid flows. In some embodiments, the insulating sub-layer 324b can be molded, sprayed, or otherwise take the form of a protective sleeve. In some embodiments, the insulating sub-layer 324b may implement nano-particle technology, and/or may be thin, e.g., a fraction of a millimeter, to several millimeters thick. In some embodiments, the insulating sub-layer 324b may provide anti-erosion, anti-abrasion properties, and/or electrical insulating properties.
In some implementations, the width, thickness, and material used as the conductive sub-layer 322 may be selected based on the amount of data or power that is expected to be transmitted through it. In some implementations, the conductive material, geometry, and/or location conductive sub-layer 322 may be selected to allow for the bending, compressing, and/or stretching of the drilling tubulars as is experienced in a downhole drilling environment.
The conductive strip layer 522 is arranged substantially parallel to the longitudinal geometry of the inner surface of the insulating sub-layer 524a. The conductive strip layer 522 is electrically insulated from the tubular housing 510 by the insulating sub-layer 524a, and is electrically insulated from the bore of the stator 500 by an insulating sub-layer 524b. The conductive strip layer may take a helical form in the bore of the housing or may be of other regular or irregular geometry.
The conductive layers 422a-422b are concentric layers formed to substantially conform to the geometry of the inner surface of the tubular housing 410. The conductive layer 420a is separated from the tubular housing 410 by an insulating sub-layer 424a. The conductive layers 422a-422b are separated by the insulating sub-layers 424b of
The implementation 800 can provide efficient and reliable electronic power and/or data transmission through downhole tools and/or drill strings. Power and/or data can be conducted through insulated conducting sleeves, e.g., the conductive sub-layer 322 and the insulating sub-layers 324a, 324b, which can form a solid part of drilling equipment cylindrical tubular components such as the stator 300. In some implementations, the stator 300 may provide electrical connectivity without significantly impacting the physical operational integrity of the drilling equipment components, e.g., the cross-sectional geometry of the stator 300 may not be significantly impacted by the inclusion of the conductive sub-layer 322 and the insulating sub-layers 324a, 324b. In some implementations, adverse drilling fluid erosion, corrosion, vibration, and/or shock loading effects on the conductor may be reduced. For example, the flow of fluid through the bore of the stator 300 may be substantially unaffected by the presence of the conductive sub-layer 322 and the insulating sub-layers 324a, 324b, since the bore of the stator 300 can be formed with an inner surface geometry that is similar to stators not having insulated conducting sleeves, such as the example drill string 20 of
The conductive sub-layer 722 is formed along the complex inner surface of the insulated layer 720 which is applied to the metal insert layer 715 (or alternatively the bore of the housing 210). In some embodiments, the conductive sub-layer 722 may be an electrically conductive sleeve or strip that is inserted or otherwise applied to the inner surface of the elastomer layer 715. In some embodiments, the conductive sub-layer 722 may be a fluid or particulate compound that is sprayed, coated, or otherwise deposited upon the inner surface of the metal insert layer 715.
The insulating sub-layer 724 is formed along the concentrically inward surface of the conductive sub-layer 722. The insulating sub layer 724 may be polymeric and therefore deformable when the rotor is rotated inside the stator assembly. The insulating sub-layer 724 can protect the conductive sub-layer 722 from the erosive and abrasive conditions that may be present within the bore, e.g., wear from contact with the rotor 730, wear from mud or other fluid flows, chemical degradation due to substances carried by mud or fluid flows. In some embodiments, the insulating sub-layer 724 can be molded, sprayed, or otherwise take the form of a protective sleeve. In some embodiments, the insulating sub-layer 724 may implement nano-particle technology, and/or may be thin, e.g., a fraction of a millimeter to several millimeters thick. In some embodiments, the insulating sub-layer 724 may provide anti-erosion, anti-abrasion properties, and/or electrical insulating properties.
In some embodiments, the elastomer layer 720 applied to metal layer 715 can provide electrical insulation. For example, the elastomer layer 720 applied on metal layer 715 may also perform the function of an insulating sub-layer between the conductive sub-layer 722 and the tubular housing 710.
A conductive sub-section 1526a and a conductive sub-section 1526b are formed within a portion of the insert layer 1522. In some embodiments, the conductive sub-sections 1526a, 1526b may be electrically conductive sleeves or plugs that are inserted or otherwise applied to sub-sections of the insert layer 1522.
In some embodiments, the insert layer 1522 can provide electrical insulation. For example, the insert layer 1522 may also perform the function of an insulating sub-layer between the conductive sub-sections 1526a, 1526b and the tubular housing 1510.
Referring again to
In some embodiments, the conductive sub-sections 1526a, 1526b may be replaced by open, e.g., unfilled, sub-sections. For example, the stator sections 1570 can be oriented such that the open sub-sections substantially align and form a bore along the length of the stator 1500. In some embodiments, one or more conductive wires or laminated conductive sleeves may be passed through the bore formed by the open sub-sections.
A conductive sub-section 1626a and a conductive sub-section 1626b are formed within a portion of the elastomer layer 1622. In some embodiments, the conductive sub-sections 1626a, 1626b may be electrically conductive sleeves or plugs that are inserted or otherwise applied to sub-sections of the elastomer layer 1622.
In some embodiments, the conductive sub-sections 1626a, 1626b can include one or more electrically insulating and/or conductive sub-layers. For example the conductive sub-sections 1626a, 1626b may each include an electrically conductive sub-layer surrounded by an electrically insulating sub-layer, e.g., to prevent the electrically conductive sub-layer from shorting out to the tubular housing 1610. In some embodiments, the conductive sub-sections 1626a, 1626b may be replaced by open, e.g., unfilled, sub-sections. For example, one or more electrical conductors may be passed through the open subsections to provide an electrical signal path along the length of the stator 1600
In some implementations, the stators 300, 400, 500, 600, 705, 905, 1005 and/or 1105a-1105f may be used in conjunction with existing threaded connection conductor couplings, e.g., ring type couplings which fit between a pin connection nose and a box connection bore back upon tubular component assembly, to permit electronic signal and data to travel between components located along a drill string
At 1205, an outer housing is provided. For example, in the example of
At 1210, a first protective layer is provided. For example, the insulating sub-layer 324a is formed as an inwardly concentric layer upon the tubular housing 310.
At 1215, an electrically conductive layer is provided. For example, the conductive sub-layer 322 is formed along the interior surface of the insulating sub-layer 324a.
At 1220, a second protective layer is provided. For example, the insulating sub-layer 324b is formed as an inwardly concentric layer upon the conductive sub-layer 322.
At 1225, electric current is applied to the electrically conductive layer at a first end. For example, electrical power from the first electrical device 810 is applied to the conductive sub-layer 322 at the first end 830.
At 1230, electric current is flowed along the electrically conductive layer. The electric current may include an electrical signal being transmitted and/or an electrical power being conducted. For example, the first electrical device 810 can provide an electrical signal to the first end 830, and the signal can be transmitted along the conductive sub-layer 322 to the second end 840 or alternatively instead of a signal, electrical power may be conducted through the conductive sub layer and used to power a device in the tool string (see
At 1235, electric current is received from the electrically conductive layer at a second end. For example, the second electrical device 820 is connected to the conductive sub-layer 322 to receive the signal that has been transmitted from the first electrical device 810 or alternatively receive the electrical power conducted through the conductive layer. It will be appreciated that a signal may be transmitted in either directions through the conductive layer and electrical power may be transmitted in either direction through the conductive layer (see
Although a few implementations have been described in detail above, other modifications are possible. For example, the logic flows depicted in the figures do not require the particular order shown, or sequential order, to achieve desirable results. In addition, other steps may be provided, or steps may be eliminated, from the described flows, and other components may be added to, or removed from, the described systems. Accordingly, other implementations are within the scope of the following claims.
Filing Document | Filing Date | Country | Kind |
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PCT/US2013/040076 | 5/8/2013 | WO | 00 |
Publishing Document | Publishing Date | Country | Kind |
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WO2014/182293 | 11/13/2014 | WO | A |
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Number | Date | Country | |
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20140332272 A1 | Nov 2014 | US |