Fluid pressure pulse generator for a downhole telemetry tool

A fluid pressure pulse generator for a downhole telemetry tool comprising a stator and a rotor. The stator has a stator body and a plurality of radially extending stator projections spaced around the stator body, with adjacently spaced stator projections defining stator flow channels extending therebetween. The rotor has a rotor body and a plurality of radially extending rotor projections spaced around the rotor body, with adjacently spaced rotor projections defining rotor flow channels extending therebetween. The rotor projections are axially adjacent the stator projections. The rotor is rotatable relative to the stator and is configured to oscillate from an open flow position an equal span of clockwise and counter clockwise rotation to first and second restricted flow positions. In the open flow position the rotor projections align with the stator projections with an axial central line of the stator projections circumferentially offset from an axial central line of the rotor projections and the rotor flow channels are in fluid communication with the stator flow channels so that drilling fluid flows through the fluid pressure pulse generator apparatus. In the first and second restricted flow positions the rotor projections are in fluid communication with the stator flow channels to create a pressure pulse in the drilling fluid flowing through the fluid pressure pulse generator apparatus. The equal span of clockwise and counter clockwise rotation is selected so that a gap is formed between the rotor projections and the stator projections in at least one of the first and second restricted flow positions for flow of drilling fluid therethrough and a greater proportion of the rotor projections is in fluid communication with the stator flow channels in one of the first and second restricted flow positions than in the other of the first and second restricted flow positions. The fluid pressure pulse generator creates pressure pulses with different pulse heights through symmetrical rotation of the rotor relative to the stator.

FIELD

This disclosure relates generally to a fluid pressure pulse generator for a downhole telemetry tool, such as a mud pulse telemetry measurement-while-drilling (“MWD”) tool.

BACKGROUND

The recovery of hydrocarbons from subterranean zones relies on the process of drilling wellbores. The process includes drilling equipment situated at surface, and a drill string extending from the surface equipment to a below-surface formation or subterranean zone of interest. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. The process also involves a drilling fluid system, which in most cases uses a drilling “mud” that is pumped through the inside of piping of the drill string to cool and lubricate the drill bit. The mud exits the drill string via the drill bit and returns to surface carrying rock cuttings produced by the drilling operation. The mud also helps control bottom hole pressure and prevent hydrocarbon influx from the formation into the wellbore, which can potentially cause a blow out at surface.

Directional drilling is the process of steering a well from vertical to intersect a target endpoint or follow a prescribed path. At the terminal end of the drill string is a bottom-hole-assembly (“BHA”) which comprises 1) the drill bit; 2) a steerable downhole mud motor of a rotary steerable system; 3) sensors of survey equipment used in logging-while-drilling (“LWD”) and/or measurement-while-drilling (“MWD”) to evaluate downhole conditions as drilling progresses; 4) means for telemetering data to surface; and 5) other control equipment such as stabilizers or heavy weight drill collars. The BHA is conveyed into the wellbore by a string of metallic tubulars (i.e. drill pipe). MWD equipment is used to provide downhole sensor and status information to surface while drilling in a near real-time mode. This information is used by a rig crew to make decisions about controlling and steering the well to optimize the drilling speed and trajectory based on numerous factors, including lease boundaries, existing wells, formation properties, and hydrocarbon size and location. The rig crew can make intentional deviations from the planned wellbore path as necessary based on the information gathered from the downhole sensors during the drilling process. The ability to obtain real-time MWD data allows for a relatively more economical and more efficient drilling operation.

One type of downhole MWD telemetry known as mud pulse telemetry involves creating pressure waves (“pulses”) in the drill mud circulating through the drill string. Mud is circulated from surface to downhole using positive displacement pumps. The resulting flow rate of mud is typically constant. The pressure pulses are achieved by changing the flow area and/or path of the drilling fluid as it passes the MWD tool in a timed, coded sequence, thereby creating pressure differentials in the drilling fluid. The pressure differentials or pulses may be either negative pulses or positive pulses. Valves that open and close a bypass stream from inside the drill pipe to the wellbore annulus create a negative pressure pulse. All negative pulsing valves need a high differential pressure below the valve to create a sufficient pressure drop when the valve is open, but this results in the negative valves being more prone to washing. With each actuation, the valve hits against the valve seat and needs to ensure it completely closes the bypass; the impact can lead to mechanical and abrasive wear and failure. Valves that use a controlled restriction within the circulating mud stream create a positive pressure pulse. Pulse frequency is typically governed by pulse generator motor speed changes. The pulse generator motor requires electrical connectivity with the other elements of the MWD probe.

One type of valve mechanism used to create mud pulses is a rotor and stator combination where a rotor can be rotated relative to the fixed stator between an open flow position where there is no restriction of mud flowing through the valve and no pulse is generated, and a restricted flow position where there is restriction of mud flowing through the valve and a pressure pulse is generated.

SUMMARY

According to a first aspect, there is provided a fluid pressure pulse generator apparatus for a downhole telemetry tool, comprising a stator and a rotor. The stator comprises a stator body and a plurality of radially extending stator projections spaced around the stator body, whereby adjacently spaced stator projections define stator flow channels extending therebetween. The rotor comprises a rotor body and a plurality of radially extending rotor projections spaced around the rotor body, whereby adjacently spaced rotor projections define rotor flow channels extending therebetween. The rotor projections are axially adjacent the stator projections. The rotor is rotatable relative to the stator and is configured to oscillate from an open flow position an equal span of clockwise and counter clockwise rotation to first and second restricted flow positions. In the open flow position the rotor projections align with the stator projections with an axial central line of the stator projections circumferentially offset from an axial central line of the rotor projections and the rotor flow channels are in fluid communication with the stator flow channels so that drilling fluid flows through the fluid pressure pulse generator apparatus. In the first and second restricted flow positions the rotor projections are in fluid communication with the stator flow channels to create a pressure pulse in the drilling fluid flowing through the fluid pressure pulse generator apparatus. The equal span of clockwise and counter clockwise rotation is selected so that a gap is formed between the rotor projections and the stator projections in at least one of the first and second restricted flow positions for flow of drilling fluid therethrough. A greater proportion of the rotor projections are in fluid communication with the stator flow channels in one of the first and second restricted flow positions than in the other of the first and second restricted flow positions.

The rotor projections may be downhole relative to the stator projections. The rotor projections may have a radial profile with an uphole end, a downhole end and two opposed side faces extending therebetween. A section of the radial profile of at least one of the rotor projections may be tapered towards the uphole end, whereby if rotation is stopped when the tapered section of the at least one rotor projection is in fluid communication with the stator flow channels the drilling fluid impinging on the tapered section moves the rotor until the tapered section of the at least one rotor projection is out of fluid communication with the stator flow channels. At least one of the side faces of the tapered rotor projection may have a bevelled uphole edge or both of the side faces of the tapered rotor projection may have a bevelled uphole edge.

The stator projections may have a radial profile with an uphole end, a downhole end and two opposed side faces extending therebetween. The uphole end of at least one of the stator projections may be rounded. A section of the radial profile of at least one of the stator projections may be tapered towards the uphole end.

At least one of the rotor projections may taper radially in the downhole direction. The at least one radially tapered rotor projection may be longitudinally extended.

An uphole end of the stator body may be configured to fixedly attach to a downhole end of a pulser assembly of the downhole telemetry tool. An uphole end of the stator body may be configured to couple with a downhole end of a pulser assembly of the downhole telemetry tool. The stator body may have a bore therethrough and at least a portion of the rotor body may be received within the bore. The rotor body may have a bore therethrough configured to receive a downhole portion of a driveshaft extending from the pulser assembly. The apparatus may further comprise a rotor cap comprising a cap body and a shaft which is received in the bore of the rotor body. The rotor cap may be configured to releasably attach the rotor to the driveshaft. A downhole end of the cap body may be rounded.

According to a second aspect, there is provided a downhole telemetry tool comprising a pulser assembly and the fluid pressure pulse generator apparatus of the first aspect. The pulser assembly comprises a housing, a motor fixedly coupled to the housing, and a driveshaft rotationally coupled to the motor. The driveshaft is fixedly attached to the rotor and the motor can rotate the driveshaft and the rotor relative to the stator.

According to a second aspect, there is provided a downhole telemetry tool comprising a pulser assembly and the fluid pressure pulse generator apparatus of the first aspect. The pulser assembly comprises a housing enclosing a motor and a driveshaft rotationally coupled to the motor. The driveshaft is coupled to the rotor and the motor can rotate the driveshaft and the rotor relative to the stator.

According to another aspect, there is provided a method of generating a fluid pressure pulse pattern in downhole drilling fluid comprising a first fluid pressure pulse and a second fluid pressure pulse whereby the first fluid pressure pulse is greater than the second fluid pressure pulse. The method comprises providing the downhole telemetry tool of the second aspect, and controlling the motor to oscillate the rotor between the open flow position and the first and second restricted flow positions, whereby rotation to one of the first and second restricted flow positions creates the first pressure pulse and rotation to the other of the first and second restricted flow positions creates the second pressure pulse.

DETAILED DESCRIPTION OF EMBODIMENTS

Directional terms such as “uphole” and “downhole” are used in the following description for the purpose of providing relative reference only, and are not intended to suggest any limitations on how any apparatus is to be positioned during use, or to be mounted in an assembly or relative to an environment.

The embodiments described herein generally relate to a fluid pressure pulse generator of a MWD tool that can generate pressure pulses. The fluid pressure pulse generator may be used for mud pulse (“MP”) telemetry used in downhole drilling, wherein a drilling fluid (herein referred to as “mud”) is used to transmit telemetry pulses to surface. The fluid pressure pulse generator may alternatively be used in other methods where it is necessary to generate a fluid pressure pulse. The fluid pressure pulse generator comprises a stator fixed to a pulser assembly of the MWD tool or the drill collar and a rotor coupled to a motor in the pulser assembly which rotates the rotor relative to the fixed stator.

Referring to the drawings and specifically toFIG. 1, there is shown a schematic representation of a MP telemetry operation using a fluid pressure pulse generator30according to embodiments described herein. In downhole drilling equipment1, drilling mud is pumped down a drill string by pump2and passes through a measurement while drilling (“MWD”) tool20. The MWD tool20includes a fluid pressure pulse generator30. The fluid pressure pulse generator30has an open flow position in which mud flows relatively unimpeded through the pressure pulse generator30and no pressure pulse is generated, a full restricted flow position where flow of mud through the pressure pulse generator30is restricted and a full positive pressure pulse is generated (represented schematically as block6in mud column10), and a partial restricted flow position where flow of mud through the pressure pulse generator30is partially restricted and a reduced positive pressure pulse is generated (represented schematically as block5in mud column10). Reduced pressure pulse5is of a smaller pulse height compared to the full pressure pulse6. Information acquired by downhole sensors (not shown) is transmitted in specific time divisions by pressure pulses5,6in the mud column10. More specifically, signals from sensor modules in the MWD tool20, or in another downhole probe (not shown) communicative with the MWD tool20, are received and processed in a data encoder in the MWD tool20where the data is digitally encoded as is well established in the art. This data is sent to a controller in the MWD tool20which then actuates the fluid pressure pulse generator30to generate pressure pulses5,6which contain the encoded data. The pressure pulses5,6are transmitted to the surface and detected by a surface pressure transducer7and decoded by a surface computer9communicative with the transducer by cable8. The decoded signal can then be displayed by the computer9to a drilling operator. The characteristics of the pressure pulses5,6are defined by duration, shape, and frequency; these characteristics are used in various encoding systems to represent binary data. The ability of the pressure pulse generator30to produce two different sized (height) pressure pulses5,6, may allow for greater variation in the binary data being produced and therefore may provide quicker and more accurate interpretation of downhole measurements.

Referring toFIGS. 2aand 2b, a mud pulser section of the MWD tool20is shown in more detail. The MWD tool20generally comprises the fluid pressure pulse generator30which creates fluid pressure pulses, and a pulser assembly26which takes measurements while drilling and which drives the fluid pressure pulse generator30. The fluid pressure pulse generator30and pulser assembly26are axially located inside a drill collar27. A flow bypass sleeve170according to a first embodiment is received inside the drill collar27and surrounds the fluid pressure pulse generator30. The flow bypass sleeve170is described in more detail below with reference toFIGS. 9 to 11. The pulser assembly26is fixed to the drill collar27with an annular channel55therebetween, and mud flows along the annular channel55when the MWD tool20is downhole. The pulser assembly26includes pulser assembly housing49enclosing a motor subassembly25and an electronics subassembly28electronically coupled together but fluidly separated by a feed-through connector (not shown). The motor subassembly25includes a motor and gearbox subassembly23, a driveshaft24connected to the motor and gearbox subassembly23, and a pressure compensation device48. As described in more detail below with reference toFIGS. 3 to 8, the fluid pressure pulse generator30comprises a stator40and a rotor60. The stator40comprises a stator body41fixed to the pulser assembly housing49and stator projections42radially extending around the downhole end of the stator body41. The rotor60comprises a rotor body69fixed to the driveshaft24and rotor projections62radially extending around the downhole end of the rotor body69. Rotation of the driveshaft24by the motor and gearbox subassembly23rotates the rotor60relative to the fixed stator40. The electronics subassembly28includes downhole sensors, control electronics, and other components (not shown) required by the MWD tool20to determine direction and inclination information and to take measurements of drilling conditions, to encode this data using one or more known modulation techniques into a carrier wave, and to send motor control signals to the motor and gearbox subassembly23to rotate the driveshaft24and rotor60in a controlled pattern to generate pressure pulses5,6representing the carrier wave for transmission to surface.

The motor subassembly25is filled with a lubricating liquid such as hydraulic oil or silicon oil and this lubricating liquid is fluidly separated from mud flowing along the annular channel55by an annular seal54which surrounds the driveshaft24. The pressure compensation device48comprises a flexible membrane (not shown) in fluid communication with the lubrication liquid on one side and with mud on the other side via ports50in the pulser assembly housing49; this allows the pressure compensation device48to maintain the pressure of the lubrication liquid at about the same pressure as the mud at the fluid pressure pulse generator30. Without pressure compensation, the torque required to rotate the driveshaft24and rotor60would need high current draw with excessive battery consumption resulting in increased costs. In alternative embodiments (not shown), the pressure compensation device48may be any pressure compensation device known in the art, such as pressure compensation devices that utilize pistons, metal membranes, or a bellows style pressure compensation mechanism.

The fluid pressure pulse generator30is located at the downhole end of the MWD tool20. Mud pumped from the surface by pump2flows along annular channel55between the outer surface of the pulser assembly26and the inner surface of the drill collar27. When the mud reaches the fluid pressure pulse generator30it flows along an annular channel56between the external surface of the stator body41and the internal surface of the flow bypass sleeve170. The rotor60rotates relative to the fixed stator40between an open flow position where mud flows freely through the fluid pressure pulse generator30resulting in no pressure pulse, a full restricted flow position where flow of mud is restricted to generate full pressure pulse6, and a partial restricted flow position where flow of mud is partially restricted to generate reduced pressure pulse5, as will be described in more detail below with reference toFIGS. 3 to 8.

Referring now toFIGS. 3 to 8, there is shown the stator40and rotor60which combine to form fluid pressure pulse generator30. The stator40comprises longitudinally extending stator body41with a central bore therethrough. The stator body41comprises a cylindrical section at the uphole end and a generally frusto-conical section at the downhole end which tapers longitudinally in the downhole direction. As shown inFIGS. 2A and 2B, the cylindrical section of stator body41is coupled with the pulser assembly housing49. More specifically, a jam ring58threaded onto the pulser assembly housing49is threaded on the stator body41. Once the stator40is positioned correctly, the stator40is held in place and the jam ring58is backed off and torqued onto the stator40holding it in place. The stator40surrounds annular seal54. Mud can enter the fluid pressure pulse generator30between the rotor60and the stator40however this entry point is downhole from annular seal54so the mud has to travel uphole against gravity to reach annular seal54. The velocity of mud impinging on annular seal54may therefore be reduced and there may be less wear of seal54compared to other rotor/stator designs. The external surface of the pulser assembly housing49is flush with the external surface of the cylindrical section of the stator body41for smooth flow of mud therealong. In alternative embodiments (not shown) other means of coupling the stator40with the pulser assembly housing49may be utilized and the external surfaces of the stator body41and the pulser assembly housing49may not be flush.

A plurality of radially extending stator projections42are spaced equidistant around the downhole end of the stator body41. Each stator projection42is tapered and narrower at its proximal end attached to the stator body41than at its distal end. The stator projections42have a radial profile with a rounded uphole end46and a downhole face45, with two opposed side faces47extending therebetween. A section of the radial profile of each stator projection42is tapered towards the uphole end46such that the uphole end46is narrower than the downhole face45. Mud flowing along the external surface of the stator body41contacts the rounded uphole end46of the stator projections42and flows through stator flow channels43defined by the side faces47of adjacently positioned stator projections42. The stator flow channels43are curved or rounded at their proximal end closest to the stator body41. The curved stator flow channels43, as well as the rounded uphole end46and tapered radial profile of the stator projections42may allow for smooth flow of mud through the stator flow channels43and may reduce wear of the stator projections42. In alternative embodiments (not shown) the stator projections42may be any shape and need not have a rounded uphole end46or any taper.

The rotor60comprises generally cylindrical rotor body69with a central bore therethrough and a plurality of radially extending projections62at the downhole end of rotor body69. Rotor body69is received in the bore of the stator body41. As shown inFIG. 2A, a downhole shaft24aof the driveshaft24is received in uphole end of the bore of the rotor body69and a coupling key30extends through the driveshaft24and is received in a coupling key receptacle64at the uphole end of the rotor body69to couple the driveshaft24with the rotor body69. In alternative embodiments the rotor body may be coupled with the driveshaft using magnetic coupling or some other coupling mechanism known in the art. A rotor cap90comprising a cap body91and a cap shaft92is positioned at the downhole end of the fluid pressure pulse generator30. The cap shaft92is received in the downhole end of the bore in the rotor body69and threads onto the downhole shaft24aof the driveshaft24to lock (torque) the rotor60to the driveshaft24. The cap body91includes a hexagonal shaped opening93dimensioned to receive a hexagonal Allen key which is used to torque the rotor body69to the driveshaft24. The rotor cap90therefore releasably couples the rotor60to the driveshaft24so that the rotor60may be easily removed and repaired or replaced if necessary using the Allen key. The rounded cone shaped cap body91may provide a streamlined flow path for mud and may reduce wear of the rotor projections62caused by recirculation of mud. The rounded cap body91may also reduce torque required to rotate the rotor60by reducing turbulence downhole of the rotor60. Positioning the rotor body69in the bore of the stator body41may protect the rotor body69from wear caused by mud erosion.

The radially extending rotor projections62are equidistantly spaced around the downhole end of the rotor body69and are axially adjacent and downhole relative to the stator projections42. The rotor projections62rotate in and out of fluid communication with the stator flow channels43to generate pressure pulses5,6as is described in more detail below. Each rotor projection62has a radial profile including an uphole face66and a downhole end65, with two opposed side faces67and an end face61extending between the uphole face66and the downhole end65. The rotor projections62taper from the end face61towards the rotor body69so that the rotor projections62are narrower at the point that joins the rotor body69than at the end face61. Each side face67has a bevelled or chamfered uphole edge68which is angled inwards towards the uphole face66such that an uphole section of the radial profile of each of the rotor projections62tapers in an uphole direction towards the uphole face66. A downhole section of the radial profile of each of the rotor projections62also tapers in the downhole direction towards the downhole end65, such that the width of the end face61tapers towards the downhole end65. The width of the end face61is therefore widest at a point in between the uphole face66and the downhole end65of the rotor projections62and the width of the end face61tapers from this widest point in both the uphole and downhole directions. In addition, each rotor projection62is longitudinally extended and tapers radially in the downhole direction, such that the radial thickness of the uphole face66is greater than the radial thickness of the downhole end65giving the rotor projections62a wedge like shape. The wedge shaped rotor projections62therefore taper both along their axis and radially. The wedge shaped rotor projections62may be stronger and less fragile compared to the rotor projections62which are not longitudinally extending or radially tapered. In addition, the radial taper of the wedge shaped rotor projections62may reduce the amount of recirculation of mud downstream of the rotor projections62compared to fluid pressure pulse generators30having a sudden mud expansion region downstream of the rotor projections62. Reducing the amount of recirculation of mud downstream of the rotor projections62may reduce erosion and cavitations of the rotor60and stator40caused by recirculation of mud.

In alternative embodiments (not shown) the rotor projections62may be any shape and need not be longitudinally extended or radially tapered with a wedge like shape or they may not have a bevelled uphole edge68or any taper. The innovative aspects apply equally in embodiments such as these.

In the open flow position shown inFIGS. 4A, 4B and 8A, rotor flow channels63defined by the side faces67of adjacently positioned rotor projections62align with and are in fluid communication with the stator flow channels43, so that mud flows freely through the flow channels43,63resulting in no pressure pulse. The rotor flow channels63are curved or rounded at the proximal end closest to the rotor body69for smooth flow of mud therethrough which may reduce wear of the rotor projections42. The rotor projections62each align with one of the stator projections42. The uphole face66of each rotor projection62is narrower than the downhole face45of the aligned stator projection42and the rotor projections62are not centrally positioned with respect to the stator projections42; instead an axial central line of the rotor projections62is circumferentially offset from an axial central line of the stator projections42.

To generate the full pressure pulse6, the rotor60rotates from the open flow position thirty degrees counter clockwise to the full restricted flow position shown inFIGS. 7 and 8C. In the full restricted flow position the rotor projections62align with the stator flow channels43and flow of mud through the stator flow channels43is restricted generating full pressure pulse6. The rotor then rotates thirty degrees clockwise back to the open flow position.

To generate the reduced pressure pulse5, the rotor60rotates from the open flow position thirty degrees clockwise to the partial restricted flow position shown inFIGS. 6 and 8B. In the partial restricted flow position the rotor projections62partially align with the stator flow channels43. A gap52between the stator projections42and the rotor projections62allows some mud to flow from the stator flow channels43to the rotor flow channels63; however the flow of mud through the stator flow channels43is partial restricted by the rotor projections62generating reduced pressure pulse5. The rotor then rotates thirty degrees counter clockwise back to the open flow position. As more mud can flow through the fluid pressure pulse generator30when the rotor60is in the partial restricted flow position than when the rotor60is in the full restricted flow position, reduced pressure pulse5is smaller in height than full pressure pulse6.

As discussed above, the rotor projections62are narrower and circumferentially offset with regards to the stator projections42. This results in a larger proportion of each rotor projection62being in fluid communication with the stator flow channels43when the rotor60rotates thirty degrees counter clockwise from the open flow position to the full restricted flow position than when the rotor60rotates thirty degrees clockwise from the open flow position to the partial restricted flow position. Therefore the amount of mud that can flow from the stator flow channels43through the rotor flow channels63in the full restricted flow position is less than the amount of mud that can flow from the stator flow channels43through the rotor flow channels63in the partial restricted flow position, generating full pressure pulse6and reduced pressure pulse5respectively. The rotor60is rotated an equal span of rotation (i.e. thirty degrees) from the open flow position clockwise to the partial restricted flow position and from the open flow position counter clockwise to the full restricted flow position, to generate the full and reduced pressure pulses5,6respectively. The fluid pressure pulse generator30is therefore able to generate pressure pulses5,6with different pulse heights through equal or symmetrical rotation of the rotor60in the clockwise and counter clockwise direction from the open flow position. The MWD tool20of the disclosed embodiments may therefore use mechanical features of the fluid pressure pulse generator30to generate pressure pulses5,6with different pulse heights through symmetrical rotation of the rotor60rather than having to rely on electronic capabilities of the motor and the controller to be able to rotate the rotor60a different rotational span in the clockwise and counter clockwise direction to generate pressure pulses with different pulse heights. Symmetrical rotation of the rotor60about a central start (open flow) position may also help maintain accurate calibration of the rotor60relative to the stator40.

In alternative embodiments (not shown) the equal span of rotation of the rotor60from the open flow position to the full and partial restricted flow positions may be more or less than thirty degrees, however in each embodiment there is a substantially equal span of rotation from the open flow position in one direction to the full restricted flow position and in the opposite direction to the partial restricted flow position. The substantially equal span of clockwise and counter clockwise rotation is selected so that there is a gap52between the rotor projections62and the stator projections42when the rotor60is in the partial restricted flow position in order to generate reduced pressure pulse5. There may also be a gap between the rotor projections62and the stator projections42when the rotor60is in the full restricted flow position, however due to the circumferential offset of the rotor projections62relative to the stator projections42, the gap in the full restricted flow position is less than the gap52in the partial restricted flow position so that less mud flows through the fluid pressure pulse generator30in the full restricted flow position than in the partial restricted flow position. Alternatively, there may be no gap in the full restricted flow position as provided in the embodiment shown inFIG. 7.

During operation of the fluid pressure pulse generator30, the rotor60oscillates back and forth between the open flow position and the full and partial restricted flow positions in a staged oscillation method to generate a pattern of pressure pulses5,6. More specifically, the rotor60starts in the open flow position with zero pressure and rotates to either the full restricted flow position or the partial restricted flow position depending on the pressure pulse pattern desired. The rotor60returns to the open flow position before generating the next pressure pulse which allows for a constant reset of timing and position for signal processing and precise control. The open flow position at the central point of the rotational span of the rotor60provides zero pressure and a clear indication of the end of a previous pulse and start of a new pulse. Also if the rotor60is impacted or knocked during operation or otherwise moves out of position, the rotor60can return to the open flow position to recalibrate and start over. This may reduce the potential for error over the long term performance of the fluid pressure pulse generator30.

A precise pattern of pressure pulses can be generated through rotation of the rotor60from the open flow position an equal span of clockwise and counter clockwise rotation (e.g. thirty degrees in a clockwise direction and thirty degrees in a counter clockwise direction). As the rotor60is rotated in both clockwise and counter clockwise directions, there may be less wear than if the rotor is only rotated in one direction. Furthermore, the span of rotation is limited which may reduce wear of the motor, seals, and other components associated with rotation. In alternative embodiments (not shown) more or less rotor projections62and stator projections42may be present on the fluid pressure pulse generator30and the span of rotation of the described staged oscillation method may vary depending on the amount of rotation required to rotate the rotor between the open flow position and the full and partial restricted flow positions. The frequency of pressure pulses5,6that can be generated may be increased with a reduced span of rotation of the rotor60and, as a result, the data acquisition rate may be increased.

It will be evident from the foregoing that provision of more stator projections42and rotor projections62will reduce the amount of rotation required to move the rotor60between the open and restricted flow positions, thereby increasing the speed of data transmission; however the number of stator projections42and rotor projections62may be limited by the circumferential area of the stator body41and rotor body69being able to accommodate the stator projections42and rotor projections62respectively. In order to accommodate more stator projections42and rotor projections62if data transmission speed is an important factor, the width of the stator projections42and rotor projections62can be decreased to allow for more stator projections42and rotor projections62to be present. The innovative aspects apply equally in embodiments such as these.

Provision of multiple stator projections42and rotor projections62provides redundancy and allows the fluid pressure pulse generator30to continue working when there is damage to one of the stator projections42and/or rotor projections62or blockage of one of the stator flow channels43and/or rotor flow channels63. Cumulative flow of mud through the remaining undamaged or unblocked stator flow channels43and/or rotor flow channels63may still result in generation of detectable pressure pulses5,6, even though the pulse heights may not be the same as when there is no damage or blockage.

Provision of two restricted flow positions which generate different pulse heights enables the fluid pressure pulse generator30to operate using the full restricted flow position, the partial restricted flow position or both restricted flow positions to generate pressure pulses depending on mud flow conditions downhole. For example, for high mud flow rate conditions, the pressure generated when the rotor60is in the full restricted flow position may be too great and cause damage to the fluid pressure pulse generator30. The fluid pressure pulse generator30may therefore operate using only the partial restricted flow position to generate reduced pressure pulses5detectable at the surface. For lower mud flow rate conditions, reduced pressure pulses5generated by rotation of the rotor60to the partial restricted flow position may be too small to be detectable at the surface. The fluid pressure pulse generator30may therefore operate using only the full restricted flow position to generate full pressure pulses6detectable at the surface. Thus it may be possible for downhole drilling to continue when the mud flow conditions change without having to change the fluid pressure pulse generator30. For normal mud flow conditions, the fluid pressure pulse generator30may operate using both the full restricted flow position and the partial restricted flow position to produce different height pressure pulses5,6to increase the data transmission rate of the fluid pressure pulse generator30.

The bevelled edges68of the side faces67of the rotor projections62provide a self correction mechanism to move the rotor60to the open flow position if there is failure of the motor and gearbox subassembly23, driveshaft24or any other component of the MWD tool20that results in rotation of the rotor60stopping during downhole operation. More specifically, if the pulser assembly26fails when the bevelled edges68of the side faces67of the rotor projections62are in the mud flow path, mud impinging on the bevelled edges68causes the rotor projections62to move in a counter clockwise or clockwise direction until the rotor60reaches the open flow position. The direction the rotor60moves to reach the open flow position depends on the angle of the bevelled edges68in the mud flow path. Once the rotor60reaches the open flow position, both bevelled edges68of the rotor projections62are positioned below the stator projections42and out of the mud flow path and the rotor60remains stationary until the driveshaft24and rotor60is once again rotated by the motor and gearbox subassembly23. The tapered stator projections42may direct mud towards the bevelled edges68and may increase the rotational force created by mud impinging on the bevelled edges68.

In alternative embodiments (not shown) the angle of the bevelled edge68of one side face67may be different to the angle of the bevelled edge68of the opposed side face67of each rotor projection62, or only one of the opposed side faces67may include a bevelled edge68. The proportion of each side face67that is angled or bevelled may also vary and in alternative embodiments (not shown) the rotor projections62may taper from the downhole end65to the uphole face66. In further alternative embodiments, none or not all of the rotor projections62may have a bevelled edge68and some side faces67may instead be perpendicular to or angled away from the uphole face66.

Rotational force provided by the motor and gearbox subassembly23may be required to rotate the rotor60from the open flow position to the restricted flow positions. If the applied rotational force stops, the rotor60will self correct and move to the open flow position and remain in the open flow position until the rotational force is applied again. Providing a self-correcting rotor60that moves to the open flow position if there is failure of the pulser assembly may reduce pressure build up caused by the rotor60being held in the full restricted flow position, or partial restricted flow position for an extended period of time following failure of the pulser assembly26. Without self-correction, the pressure build up may lead to damage of the rotor60and/or stator40. The pressure build up may also lead to failure of the pumps or piping on surface. Furthermore, self correction of the rotor60to the open flow position may reduce or prevent debris or loss circulation material (LCM) build up which could plug the drill collar27and restrict mud flow. Self correction of the rotor60to the open flow position may also reduce the torque required to rotate the rotor60from the restricted flow positions to the open flow position during normal operation. In alternative embodiments (not shown), the rotor may include an alternative self-correction mechanism, or no self-correction mechanism, and the bevelled edges68of the rotor projections62and taper of the stator projections42may not be present.

In alternative embodiments (not shown), the rotor projections62may be axially adjacent and uphole relative to the stator projections42. The stator projections42may be narrower than the rotor projections62to protect the downhole stator projections42from wear. In further alternative embodiments (not shown), the fluid pressure pulse generator30may be positioned at the uphole end of the MWD tool20. In these alternative embodiments, the rotor projections62are circumferentially offset with respect to the stator projections42when the rotor60is in the open flow position and there is symmetrical or equal span of rotation of the rotor projections62relative to the stator projections42from the open flow position in one direction to the full restricted flow position and in the opposite direction to the partial restricted flow position to generate full pressure pulse6and reduced pressure pulse5respectively. A greater proportion of the rotor projections62is in fluid communication with the stator flow channels43in the full restricted flow position compared to the partial restricted flow position such that more mud can flow through the fluid pressure pulse generator30when the rotor60is in the partial restricted flow position than in the full restricted flow position.

Referring now toFIGS. 9 to 11there is shown the flow bypass sleeve170of the first embodiment comprising a generally cylindrical sleeve body with a central bore therethrough made up of an uphole body portion171aand a downhole body portion171b. Referring toFIGS. 12 to 14a second embodiment of a flow bypass sleeve270is shown comprising a generally cylindrical sleeve body with a central bore therethrough made up of an uphole body portion271aand a downhole body portion271b.

During assembly of the first and second embodiments of the flow bypass sleeve170,270a lock down sleeve81is slid over the downhole end of downhole body portion171b,271band abuts an annular shoulder183,283on the external surface of uphole body portion171a,271arespectively. The assembled flow bypass sleeve170,270can then be inserted into the downhole end of drill collar27. The external surface of uphole body portion171a,271aincludes an annular shoulder180,280near the uphole end of uphole body portion171a,271arespectively which abuts a downhole shoulder of a keying ring (not shown) that is press fitted into the drill collar27. A keying notch184,284on the external surface of uphole body portion171a,271arespectively mates with a projection (not shown) on the keying ring to correctly align the flow bypass sleeve170,270with the pulser assembly26. A threaded ring (not shown) fixes the flow bypass sleeve170,270within the drill collar27. A groove185,285on the external surface of the uphole body portion171a,271arespectively receives an o-ring (not shown) and a rubber back-up ring (not shown) such as a parbak to help seat the flow bypass sleeve170,270and reduce fluid leakage between the flow bypass sleeve170,270and the drill collar27. In alternative embodiments the flow bypass sleeve170,270may be assembled or fitted within the drill collar27using alternative fittings as would be known to a person of skill in the art.

The lock down sleeve81may be made from a material with a higher thermal expansion coefficient than the material of the sleeve body. For example, the lock down sleeve81may comprise beryllium copper and the sleeve body may comprise Stellite. Providing different thermal expansion coefficients materials that make up the external surface of the flow bypass sleeve170,270may help clamp the flow bypass sleeve170,270within the drill collar27across a wider range of temperatures than a flow bypass sleeve comprising the same material throughout.

As shown inFIG. 2A, the diameter of the bore through the sleeve body is smallest at a central section177which surrounds the stator projections42and rotor projections62. The outer diameter of the stator projections42may be dimensioned such that the stator projections42contact the internal surface of the central section177of the sleeve body. The outer diameter of the rotor projections62is slightly less than the internal diameter of the central section177of the sleeve body to allow rotation of the rotor projections62relative to the sleeve body. The bore through the sleeve body gradually increases in diameter from the central section177towards the downhole end of the sleeve body to define an internally tapered downhole section176. The bore through the sleeve body also increases in diameter from the central section177towards the uphole end of the sleeve body to define an internally tapered uphole section179of sleeve body. The taper of the uphole section179is greater than the taper of downhole section176of sleeve body. The uphole section179of sleeve body surrounds the frusto-conical section of stator body41with the annular channel56extending therebetween. Mud flows along annular channel56and hits the stator projections42where it is channelled into the stator flow channels43. The downhole section176of the sleeve body surrounds the rotor cap body91.

In the first embodiment of the flow bypass sleeve170, the internal surface of the uphole body portion171aincludes a plurality of longitudinal extending grooves173. Grooves173are equidistantly spaced around the internal surface of the uphole body portion171a. Internal walls174in-between each groove173align with the stator projections42of the fluid pressure pulse generator30, and the grooves173align with the stator flow channels43. The flow bypass sleeve170is precisely located with respect to the drill collar27using keying notch184to ensure correct alignment of the stator projections42with the internal walls174. The rotor projections62rotate relative to the flow bypass sleeve170and move between the open flow position and the full and partial restricted flow positions as described above in more detail.

In the second embodiment of the flow bypass sleeve270a plurality of apertures275extend longitudinally through the uphole body portion271a. The apertures275are circular and equidistantly spaced around uphole body portion271a. The internal surface of the downhole body portion271bincludes a plurality of spaced grooves278which align with the apertures275in the assembled flow bypass sleeve270(shown inFIG. 14), such that mud is channeled through the apertures275and into grooves278. Alignment pins282on the uphole surface of the downhole body portion271balign with recesses (not shown) on the downhole surface of the uphole body portion271ato correctly align the apertures275with the grooves278. The internal surface of uphole body portion271awhich surrounds the rotor and stator projections162,142is uniform in this embodiment; therefore there is no need to align the stator projections42with any internal feature of the uphole body portion271aas with the first embodiment of the flow bypass sleeve170described above. The sleeve body generally needs to be wide enough to support the apertures275and the drill collar dimensions may be a limiting factor with respect to use of the second embodiment of the flow bypass sleeve270. As such, the second embodiment of the flow bypass sleeve270may be used with larger drill collars27, for example drill collars that are 8 inches or more in diameter. In alternative embodiments (not shown) the apertures275may be any shape and need not be equidistantly spaced around the sleeve body. The number and size of the apertures275may be chosen for the desired amount of mud flow therethrough. In further alternative embodiments (not shown) the grooves278may have a different shape or may not be present at all.

The external dimensions of flow bypass sleeve170,270may be adapted to fit any sized drill collar27. It is therefore possible to use a one size fits all fluid pressure pulse generator30with multiple sized flow bypass sleeves170,270with various different external circumferences that are dimensioned to fit different sized drill collars27. Each of the multiple sized flow bypass sleeves170,270may have the same internal dimensions to receive the one size fits all fluid pressure pulse generator30but different external dimensions to fit the different sized drill collars27.

In larger diameter drill collars27the volume of mud flowing through the drill collar27will generally be greater than the volume of mud flowing through smaller diameter drill collars27, however the bypass channels of the flow bypass sleeve170,279may be dimensioned to accommodate this greater volume of mud. The bypass channels of the different sized flow bypass sleeves170,270may therefore be dimensioned such that the volume of mud flowing through the one size fits all fluid pressure pulse generator30fitted within any sized drill collar27is within an optimal range for generation of pressure pulses5,6which can be detected at the surface without excessive pressure build up. It may therefore be possible to control the flow rate of mud through the fluid pressure pulse generator30using different flow bypass sleeves170,270rather than having to fit different sized fluid pressure pulse generators30to the pulser assembly26.

In alternative embodiments (not shown), the fluid pressure pulse generator30may be present in the drill collar27without the flow bypass sleeve170,270. In these alternative embodiments, the stator projections42and rotor projections62may be radially extended to have an external diameter that is greater than the external diameter of the cylindrical section of the stator body41, such that mud following along annular channel55impinges on the stator projections42and is directed through the stator flow channels43. The stator projections42and rotor projections62may radially extend to meet the internal surface of the drill collar27. There may be a small gap between the rotor projections62and the internal surface of the drill collar27to allow rotation of the rotor projections62. The innovative aspects apply equally in embodiments such as these.

While particular embodiments have been described in the foregoing, it is to be understood that other embodiments are possible and are intended to be included herein. It will be clear to any person skilled in the art that modification of and adjustments to the foregoing embodiments, not shown, are possible.