Patent Grant
10753201
This invention relates generally to downhole drilling, such as measurement-while-drilling (MWD), including mud pulse telemetry apparatuses having a pressure transducer, and methods of operating such apparatuses.
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 the formation or subterranean zone of interest. The drill string can extend thousands of feet or meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. In addition to this conventional drilling equipment, the system also relies on some sort of drilling fluid, in most cases a drilling “mud” which is pumped through the inside of the pipe, which cools and lubricates the drill bit and then exits out of the drill bit and carries rock cuttings back to surface. 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 away 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) a drill bit; 2) a steerable downhole mud motor of rotary steerable system; 3) sensors of survey equipment (Logging While Drilling (“LWD”) and/or Measurement-while-drilling (MWD)) to evaluate downhole conditions as well depth progresses; 4) equipment for telemetry of data to surface; and 5) other control mechanisms such as stabilizers or heavy weight drill collars. The BHA is conveyed into the wellbore by a metallic tubular.
As an example of a potential drilling activity, MWD equipment is used to provide downhole sensor and status information to surface in a near real-time mode while drilling. This information is used by the 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, locations of existing wells, formation properties, and hydrocarbon size and location. This can include making intentional deviations from an originally-planned wellbore path as necessary based on the information gathered from the downhole sensors during the drilling process. The ability to obtain real time data during MWD allows for a relatively more economical and more efficient drilling operation.
Known MWD tools contain essentially the same sensor package to survey the well bore but the data may be sent back to surface by various telemetry methods. Such telemetry methods include but are not limited to the use of hardwired drill pipe, acoustic telemetry, use of fibre optic cable, Mud Pulse (MP) telemetry and Electromagnetic (EM) telemetry. The sensors are usually located in an electronics probe or instrumentation assembly contained in a cylindrical cover or housing, located near the drill bit.
Mud Pulse telemetry involves creating pressure waves in the drill mud circulating inside 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 pulse 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. Some valves are hydraulically powered to reduce the required actuation power typically resulting in a main valve indirectly operated by a pilot valve. The pilot valve closes a flow restriction which actuates the main valve to create a pressure drop. 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.
In typical MWD tools, as well as other downhole tools, there are several electrical connections in the tools. Those skilled in the art will be familiar with the different types of electrical connectors commercially available for MWD and other downhole tools. The electrical connectors serve to electrically and/or communicatively couple two or more electrical devices together. The electrical connectors can vary from simple single-pin to complex multi-pin configurations and for downhole use should maintain stability and mechanical strength under downhole conditions. In many cases, electrical connections between components of a tool are configured such that a wire harness (electrical wires in bundle or pigtail) is engaged within the core of the tool, anchored at two ends with plug in connectors. By combining many wires and cables into such a harness, it can provide more security against the adverse effects of vibrations, abrasions, and moisture and reduce the risk of a short. In assembly, the wire harness can have considerable leeway within the bore of the tool and this free space allows the wires to flex, bend and vibrate as they are not secured throughout their length. Over time, the wire harnesses experience torsional and flexural fatigue which can jeopardize the function of the electrical connections. In many cases, a “snubber assembly” is incorporated in the transition between sections of tool where the electrical connectors are placed to assist in reduction or mitigation of the shock and vibration the electrical wire harness is subject to. Snubber devices in general are rubber or metal devices used to control the movement of electronic and electromechanical equipment during abnormal dynamic conditions and typical allow for free movement of a component during normal operation, but dampen shock to the component in an abnormal condition. In addition, centralizers are typically placed around the probe housing where the wire harnesses are contained within, to try to dampen some of the vibration. In downhole environments such as for directional drilling with increased temperature, shock and vibration there are still considerable failures associated with the looseness of the wire harness within the sub-assemblies. There is a high degree of failure of both the coupling devices as well as the electrical connectors so these must be routinely replaced in the downhole tools.
Typically in MWD probes which carry out mud pulse telemetry, measurement of pressure is important for optimizing drilling parameters. Some solutions have targeted the pressure transducer placement within its own separate probe; the probe tends to contain an intricate wire harness but still allows for fluid flow for data telemetry. Sometimes the transducer is exposed to the drilling fluid, which can cause erosive or corrosive failure of the transducer.
There remains a need for appropriate placement and reliable protection of downhole pressure transducers since accurate measurement of pressure in the localized downhole environment is important for efficient drilling.
According to one aspect of the invention, there is provided a pressure measurement apparatus for a downhole measurement-while-drilling tool comprising a feed through connector and a pressure transducer. The feed through connector comprises a body with a first end and an opposite second end, at least one electrical interconnection extending axially through the body and out of the first and second ends, and a pressure transducer receptacle in the first end and a communications bore extending from the receptacle to the second end. The pressure transducer is seated in the receptacle such that a pressure at the first end can be measured, and comprises at least one electrical contact that extends from the pressure transducer through the communication bore and out of the second end. A receptacle seal can be provided which extends between the pressure transducer and receptacle and establishes a fluid seal therebetween. The pressure transducer can be removably mounted in the receptacle in which case a retention clip can be provided which is removably mounted in the receptacle to secure the pressure transducer in place when seated in the receptacle. The pressure transducer can take pressure measurements used to predict wear of a primary seal in a motor subassembly of the tool, detect a pressure-related battery failure event, and control operation of a dual pulse height fluid pressure pulse generator.
The pressure measurement apparatus can be part of a fluid pressure pulse telemetry tool. This tool also comprises a fluid pressure pulse generator, a motor subassembly, and an electronics subassembly. The motor subassembly comprises a motor, a pulse generator motor housing that houses the motor, and a driveshaft extending from the motor out of the pulse generator motor housing and coupling with the pressure pulse generator. The electronics subassembly is coupled to the motor subassembly and comprises electronics equipment and an electronics housing that houses the electronics equipment. The feed through connector of the pressure measurement apparatus is located between the motor subassembly and electronics subassembly such that a fluid seal is established therebetween, the interconnection is electrically coupled to the electronics equipment and the motor, and the pressure transducer faces the motor subassembly and is communicative with the electronics equipment.
The pulse generator motor housing can further comprise an end with an annular shoulder in which the pressure measurement apparatus is seated. A feed through seal can be provided which extends between the feed through connector body and the annular shoulder such that a fluid seal is established therebetween. The pressure measurement apparatus can further comprise an annular flange extending around the feed through connector body and have at least one flange bore for receiving a fastener therethrough. The pulse generator motor housing can further comprise an end with a rim configured to mate with the flange, and at least one rim bore configured to align with the flange bore to receive the fastener such that the pressure measurement apparatus is fastened to the pulse generator motor housing. An annular seal can be located between the flange and the rim such that a fluid seal is established therebetween. Additionally, the feed through connector body can be provided with at least one open channel aligned with the flange bore such that the fastener can extend along the channel and through the flange bore.
Alternatively, a collet can be provided comprising inner threads and an annular shoulder extending around its inner surface. The pressure measurement apparatus in such case further comprises an annular flange extending around the feed through connector body and which contacts the annular shoulder to seat the pressure measurement apparatus in the collet. An end of the fluid generator motor housing comprises external threads that threadingly mate with the inner threads of the collet such that the pressure measurement apparatus is secured relative to the end of the fluid generator motor housing.
According to another aspect of the invention, the pressure measurement apparatus can be part of the electronics subassembly for a downhole measurement-while-drilling tool and be used to detect a battery failure. The electronics subassembly in this aspect also comprises an electronics housing, a battery pack, and electronics equipment. The pressure measurement apparatus is mounted inside the electronics housing such that a first compartment and a second compartment are defined inside the electronics housing on either side of the pressure measurement apparatus, and wherein the pressure transducer faces the first compartment to measure a pressure in the first compartment. The battery pack is located in the first compartment and is electrically coupled to the electrical interconnection. The electronics equipment is located in the second compartment and is electrically coupled to the electrical interconnection and the pressure transducer contact. The electronics equipment includes a controller and a memory having program code executable by the controller to perform a method comprising: reading pressure measurements from the pressure transducer, determining whether the read pressure measurements exceed a threshold component failure pressure, and initiating a component failure action when the measured pressure exceeds the threshold component failure pressure. The component failure action can comprise logging a component failure flag in the memory, and/or electrically decoupling the battery pack from the electronics equipment, and/or sending a visual or audio indication of a failure event.
According to another aspect of the invention, the pressure measurement apparatus can be part of a pulse generator motor subassembly for a downhole measurement-while-drilling tool and be used to predict wear of a primary seal in the pulse generator motor subassembly. The pulse generator motor subassembly in this aspect also comprises a housing, a fluid pressure pulse generator motor, the primary seal, and lubrication liquid. The fluid pressure pulse generator motor is located inside the housing and comprises a driveshaft extending out of a driveshaft end of the housing; the driveshaft is for coupling to a rotor of a fluid pressure pulse generator. The primary seal provides a fluid seal between the driveshaft and the housing. The pressure measurement apparatus is mounted in the housing such that it is spaced from the driveshaft end and such that the pressure transducer faces the inside of the housing. The lubrication liquid is fluidly sealed inside the housing by the pulse generator motor housing, primary seal and feed through connector of the pressure measurement device. Electronics equipment is electrically communicative with the pressure transducer, and comprises a controller and a memory having program code executable by the controller to perform a method comprising: reading a pressure measurement from the pressure transducer indicating the pressure of the lubrication liquid, determining whether the read pressure measurement falls below a threshold pressure value, and logging a unique flag in the memory when the read pressure measurement falls below the threshold pressure value. The memory can further comprise program code executable by the controller to transmit a replace seal signal and/or deactivate one or more operations of the measurement-while-drilling tool when the read pressure measurement falls below the threshold pressure value.
According to another aspect of the invention, there is provided a fluid pressure pulse telemetry apparatus comprising: a fluid pressure pulse generator, a motor subassembly, a pressure transducer, and an electronics subassembly comprising a memory with program code for operating the pulse generator between a low amplitude pulse mode and a high amplitude pulse mode. The fluid pressure pulse generator is operable to flow a drilling fluid in a full flow configuration to produce no pressure pulse, a reduced flow configuration to produce a high amplitude pressure pulse and an intermediate flow configuration to produce a low amplitude pressure pulse. The motor subassembly comprises a pulse generator motor, a pulse generator motor housing that houses the motor, and a driveshaft which extends from the motor out of the housing and couples with the pulse generator. The pressure transducer is positioned to measure a pressure of the drilling fluid flowing by the pulse generator. The electronics subassembly comprises: a controller communicative with the pressure transducer to read pressure measurements therefrom and with the motor to control operation of the pulse generator. The memory has a program code stored thereon and which is executable by the controller to perform the following method: operating the pulse generator to produce the no pressure pulse, the high amplitude pressure pulse and the low amplitude pressure pulse and reading the pressures of the no pressure pulse, high amplitude pressure pulse and low amplitude pressure pulse from the pressure transducer; determining an amplitude of the high amplitude pressure pulse and an amplitude of the low amplitude pressure pulse from the measured pressures; comparing the determined amplitudes to a low amplitude reference pressure and a high amplitude reference pressure; and operating the pulse generator between the full and intermediate flow configurations in the low amplitude pulse mode to transmit a telemetry signal to surface only when the determined amplitude of the low amplitude pressure pulse is above the low amplitude reference pressure; or, operating the pulse generator between the full and reduced flow configurations in the high amplitude pulse mode to transmit a telemetry signal to surface only when the determined amplitude of the high amplitude pressure pulse is below the high amplitude reference pressure.
The memory can further comprise program code executable by the controller to operate the pulse generator in the low amplitude pulse mode only when the determined amplitude of the low amplitude pressure pulse is below the high amplitude reference pressure. The memory can also further comprise program code executable by the controller to operate the pulse generator in the high amplitude pulse mode only when the determined amplitude of the high amplitude pressure pulse is above the low amplitude reference pressure.
The memory can further comprise program code executable by the controller to operate in the intermediate flow configuration for a selected default time period during the low amplitude pulse mode, measure the pressure and determine the amplitude of the low amplitude pressure pulse during the low amplitude pulse mode, and increase the amplitude of the low amplitude pressure pulse by operating the pulse generator in the intermediate flow configuration for a time period longer than the default time period when the determined amplitude of the low amplitude pressure pulse is below the low amplitude reference pressure.
The memory can further comprise program code executable by the controller to operate in the reduced flow configuration for a selected default time period during the high amplitude pulse mode, measure the pressure and determine the amplitude of the high amplitude pressure pulse during the high amplitude pulse mode, and increase the amplitude of the high amplitude pressure pulse by operating the pulse generator in the reduced flow configuration for a time period longer than the default time period when the determined amplitude of the high amplitude pressure pulse is below the low amplitude reference pressure.
The memory can further comprise program code executable by the controller to measure the pressure and determine the amplitude of the low amplitude pressure pulse during the low amplitude pulse mode, and operate the pulse generator in the high amplitude pulse mode when the determined amplitude of the low amplitude pressure pulse is below the low amplitude reference pressure.
The memory can further comprise program code executable by the controller to measure the pressure and determine the amplitude of the high amplitude pressure pulse during the high amplitude pulse mode, and operate the pulse generator in the low amplitude pulse mode when the determined amplitude of the high amplitude pressure pulse is above the high amplitude reference pressure.
According to another aspect of the invention, a fluid pressure pulse telemetry apparatus is provided which comprises the aforementioned fluid pressure pulse generator, motor subassembly, pressure transducer and electronics subassembly, except that the memory has program code stored thereon that is executable by the controller to perform the following method: operating the pulse generator between the full and intermediate flow configurations in a low amplitude pulse mode to transmit a telemetry signal to surface and reading the pressures of the no pulse and low amplitude pressure pulse from the pressure transducer; determining an amplitude of the low amplitude pressure pulse from the measured pressures; and when the determined amplitude of the low amplitude pressure pulse is below a low amplitude reference pressure, operating the pulse generator between the full and reduced flow configurations in a high amplitude pulse mode to transmit a telemetry signal to surface.
According to another aspect of the invention, a fluid pressure pulse telemetry apparatus is provided which comprises the aforementioned fluid pressure pulse generator, motor subassembly, pressure transducer and electronics subassembly, except that the memory has program code stored thereon that is executable by the controller to perform the following method: operating the pulse generator between the full and reduced flow configurations in a high amplitude pulse mode to transmit a telemetry signal to surface and measuring the pressures of the no pulse and high amplitude pressure pulse; and determining an amplitude of the high amplitude pressure pulse from the measured pressures; and when the determined amplitude of the high amplitude pressure pulse is above a high amplitude reference pressure, operating the pulse generator between the full and intermediate flow configurations in a low amplitude pulse mode to transmit a telemetry signal to surface.
Apparatus Overview
The embodiments described herein generally relate to a MWD tool having a fluid pressure pulse generator. The fluid pressure pulse generator of the embodiments described herein may be used for mud pulse (MP) telemetry used in downhole drilling. The fluid pressure pulse generator may alternatively be used in other methods where it is necessary to generate a fluid pressure pulse.
Referring to the drawings and specifically to
The characteristics of the pressure pulses 5, 6 are defined by amplitude, duration, shape, and frequency, and these characteristics are used in various encoding systems to represent binary data. The ability to produce two different sized pressure pulses 5, 6, allows for greater variation in the binary data being produced and therefore quicker and more accurate interpretation of downhole measurements.
One or more signal processing techniques are used to separate undesired mud pump noise, rig noise or downward propagating noise from upward MWD signals. The data transmission rate is governed by Lamb's theory for acoustic waves in a drilling mud and is about 1.1 to 1.5 km/s. The fluid pressure pulse generator 30 tends to operate in an unfriendly environment under high static downhole pressures, high temperatures, high flow rates and various erosive flow types. The fluid pressure pulse generator 30 generates pulses between 100-300 psi and typically operates in a flow rate as dictated by the size of the drill pipe bore, and limited by surface pumps, drill bit total flow area (TFA), and mud motor/turbine differential requirements for drill bit rotation.
Referring to
The motor subassembly 25 is filled with a lubricating liquid such as hydraulic oil or silicon oil; this lubricating liquid is fluidly separated from the mud flowing through the pulse generator 30; however, the pressure compensation device 48 comprises a flexible membrane 51 in fluid communication with both the mud and the lubrication liquid, which allows the pressure compensation device 48 to maintain the pressure of the lubrication liquid at about the same pressure as the drilling mud at the pulse generator 30. As will be described in more detail below, a pressure transducer 34 is seated inside the feed through connector 29 (collectively “pressure transducer and feed through subassembly 29, 34”) and faces the inside of the pulse generator motor housing. The pressure transducer 34 can thus measure the pressure of the lubrication liquid, and hence the pressure of the drilling mud; this enables the pressure transducer 34 to take pressure measurements of pressure pulses 5, 6 generated by the pulse generator 30 while being protected from the harsh environment of drilling mud.
The fluid pulse generator 30, the pressure compensation device 48, and the pressure transducer and feed through subassembly 29, 34 will now each be described in more detail:
Fluid Pressure Pulse Generator
The fluid pressure pulse generator 30 is located at the downhole end of the MWD tool 20. Drilling fluid pumped from the surface by pump 2 flows between the outer surface of the pulser assembly 26 and the inner surface of the landing sub 27. When the fluid reaches the fluid pressure pulse generator 30 it is diverted through fluid openings 67 in the rotor 60 and exits the internal area of the rotor 60 as will be described in more detail below with reference to
Referring now to
The stator 40 and rotor 60 are made up of minimal parts and their configuration beneficially provides easy line up and fitting of the rotor 60 within the stator 40. There is no positioning or height requirement and no need for an axial gap between the stator 40 and the rotor 60 as is required with known rotating disc valve pulsers. It is therefore not necessary for a skilled technician to be involved with set up of the fluid pressure pulse generator 30 and the operator can easily change or service the stator 40/rotor 60 combination if flow rate conditions change or there is damage to the rotor 60 or stator 40 during operation.
The circular body 61 of the rotor has four rectangular fluid openings 67 separated by four leg sections 70 and a mud lubricated journal bearing ring section 64 defining the downhole opening 69. The bearing ring section 64 helps centralize the rotor 60 in the stator 40 and provides structural strength to the leg sections 70. The circular body 61 also includes four depressions 65 that are shaped like the head of a spoon on an external surface of the circular body 61. Each spoon shaped depression 65 is connected to one of the fluid openings 67 by a flow channel 66 on the external surface of the body 61. Each connected spoon shaped depression 65, flow channel 66 and fluid opening 67 forms a fluid diverter and there are four fluid diverters positioned equidistant circumferentially around the circular body 61.
The spoon shaped depressions 65 and flow channels 66 direct fluid flowing in a downhole direction external to the circular body 61, through the fluid openings 67, into a hollow internal area 63 of the body, and out of the downhole opening 69. The spoon shaped depressions 65 gently slope, with the depth of the depression increasing from the uphole end to the downhole end of the depression ensuring that the axial flow path or radial diversion of the fluid is gradual with no sharp turns. This is in contrast to the stator/rotor combination described in U.S. Pat. No. 8,251,160, where windows in the stator and the rotor align to create a fluid flow path orthogonal to the windows through the rotor and stator. The depth of the spoon shaped depressions 65 can vary depending on flow parameter requirements.
The spoon shaped depressions 65 act as nozzles to aid fluid flow. Without being bound by science, it is thought that the nozzle design results in increased volume of fluid flowing through the fluid opening 67 compared to an equivalent fluid diverter without the nozzle design, such as the window fluid opening of the rotor/stator combination described in U.S. Pat. No. 8,251,160. Curved edges 71 of the spoon shaped depressions 65 also provide less resistance to fluid flow and reduction of pressure losses across the rotor/stator as a result of optimal fluid geometry. Furthermore, the curved edges 71 of the spoon shaped depressions 65 have a reduced surface compared to, for example, a channel having the same flow area as the spoon shaped depression 65. This means that the surface area of the curved edges 71 cutting through fluid when the rotor is rotated is minimized, thereby minimizing the force required to turn the rotor and reducing the pulse generator motor torque requirement. By reducing the pulse generator motor torque requirement, there is beneficially a reduction in battery consumption and less wear on the motor, beneficially minimizing costs.
Motor torque requirement is also reduced by minimizing the surface area of edges 72 of each leg section 70 which are perpendicular to the direction of rotation. Edges 72 cut through the fluid during rotation of the rotor 60 and therefore beneficially have as small a surface area as possible whilst still maintaining structural stability of the leg sections 70. To increase structural stability of the leg sections 70, the thickness at the middle of the leg section 70 furthest from the edges 72 may be greater than the thickness at the edges 72, although the wall thickness of each leg section 70 may be the same throughout. In addition, the bearing ring section 64 of the circular body 61 provides structural stability to the leg sections 70.
In alternative embodiments (not shown) a different curved shaped depression other than the spoon shaped depression may be utilized on the external surface of the rotor, for example, but not limited to, egg shaped, oval shaped, arc shaped, or circular shaped. Furthermore, the flow channel 66 need not be present and the fluid openings 67 may be any shape that allows flow of fluid from the external surface of the rotor through the fluid openings 67 to the hollow internal area 63.
The stator body 41 includes four full flow chambers 42, four intermediate flow chambers 44 and four walled sections 43 in alternating arrangement around the stator body 41. In the embodiment shown in
In use, each of the four flow sections of the stator 40 interact with one of the four fluid diverters of the rotor 60. The rotor 60 is rotated in the fixed stator 40 to provide three different flow configurations as follows:
In the full flow configuration shown in
When the rotor is positioned in the reduced flow configuration as shown in
In the intermediate flow configuration as shown in
When the rotor 60 is positioned in the reduced flow configuration as shown in
A bottom face surface 45 of both the full flow chambers 42 and the intermediate flow chambers 44 of the stator 40 may be angled in the downhole flow direction for smooth flow of fluid from chambers 42, 44 through the rotor fluid openings 67 in the full flow and intermediate flow configurations respectively, thereby reducing flow turbulence. In all three flow configurations the full flow chambers 42 and the intermediate flow chambers 44 are filled with fluid, however fluid flow from the chambers 42, 44 will be restricted unless the rotor fluid openings 67 are aligned with the full flow chambers 42 or intermediate flow chambers 44 in the full flow and intermediate flow configurations respectively.
A combination of the spoon shaped depressions 65 and flow channels 66 of the rotor 60 and the angled bottom face surface 45 of the chambers 42, 44 of the stator provide a smooth fluid flow path with no sharp angles or bends. The smooth fluid flow path beneficially minimizes abrasion and wear on the pulser assembly 26.
Provision of the intermediate flow configuration allows the operator to choose whether to use the reduced flow configuration, intermediate flow configuration or both configurations to generate pressure pulses depending on fluid flow conditions. The fluid pressure pulse generator 30 can operate in a number of different flow conditions. For higher fluid flow rate conditions, for example, but not limited to, deep downhole drilling or when the drilling mud is heavy or viscous, the pressure generated using the reduced flow configuration may be too great and cause damage to the system. The operator may therefore choose to only use the intermediate flow configuration to produce detectable pressure pulses at the surface. For lower fluid flow rate conditions, for example, but not limited to, shallow downhole drilling or when the drilling mud is less viscous, the pressure pulse generated in the intermediate flow configuration may be too low to be detectable at the surface. The operator may therefore choose to operate using only the reduced flow configuration to produce detectable pressure pulses at the surface. Thus it is possible for the downhole drilling operation to continue when the fluid flow conditions change without having to change the fluid pressure pulse generator 30. For normal fluid flow conditions, the operator may choose to use both the reduced flow configuration and the intermediate flow configuration to produce two distinguishable pressure pulses 5, 6, at the surface and increase the data rate of the fluid pressure pulse generator 30.
If one of the stator chambers (either full flow chambers 42 or intermediate flow chambers 44) is blocked or damaged, or one of the stator wall sections 43 is damaged, operations can continue, albeit at reduced efficiency, until a convenient time for maintenance. For example, if one or more of the stator wall sections 43 is damaged, the full pressure pulse 6 will be affected; however operation may continue using the intermediate flow configuration to generate intermediate pressure pulse 5. Alternatively, if one or more of the intermediate flow chambers 44 is damaged or blocked, the intermediate pulse 5 will be affected; however operation may continue using the reduced flow configuration to generate the full pressure pulse 6. If one or more of the full flow chambers 42 is damaged or blocked, operation may continue by rotating the rotor between the reduced flow configuration and the intermediate flow configuration. Although there will be no zero pressure state, there will still be a pressure differential between the full pressure pulse 6 and the intermediate pressure pulse 5 which can be detected and decoded on the surface until the stator can be serviced. Furthermore, if one or more of the rotor fluid openings 67 is damaged or blocked which results in one of the flow configurations not being usable, the other two flow configurations can be used to produce a detectable pressure differential. For example, damage to one of the rotor fluid openings 67 may result in an increase in fluid flow through the rotor such that the intermediate flow configuration and the full flow configuration do not produce a detectable pressure differential, and the reduced flow configuration will need to be used to get a detectable pressure pulse.
Provision of multiple rotor fluid openings 67 and multiple stator chambers 42, 44 and wall sections 43, provides redundancy and allows the fluid pressure pulse generator 30 to continue working when there is damage or blockage to one of the rotor fluid openings 67 and/or one of the stator chambers 42, 44 or wall sections 43. Cumulative flow of fluid through the remaining undamaged or unblocked rotor fluid openings 67 and stator chambers 42, 44 still results in generation of detectable full or intermediate pressure pulses 5, 6, even though the pulse heights may not be the same as when there is no damage or blockage.
It is evident from the foregoing that while the embodiments shown in
It is also evident from the foregoing that while the embodiments shown in
Pressure Compensation Device
Referring again to
The pressure compensation device 48 comprises a generally tubular pressure compensated housing which extends around the driveshaft 24 near the driveshaft end (otherwise referred to as the downhole end) of the motor subassembly 25 and downhole from the pulse generator motor and gearbox. The pressure compensated housing in this embodiment is an extension of the pulse generator motor housing 49 of the motor subassembly 25, but alternatively can be a separate component which is connected to the pulse generator motor housing 49. The pressure compensated housing comprises a plurality of ports 50 which extend radially through the housing wall. A cylindrical pressure compensation membrane 51 is located inside the pressure compensated housing underneath the ports 50, and is fixed in place by a pressure compensation membrane support 52. The support 52 is a generally cylindrical structure with a central bore that allows the driveshaft 24 to extend therethrough. The support 52 has two end sections with an outer diameter that abuts against the inside surface of the pressure compensated housing 49; a pair of O-ring seals each located in each end section serves to provide a fluid seal between the housing 49 and the end sections. The end sections each also has a membrane mount for mounting respective ends of the membrane 51. When the membrane 51 is mounted on the support 52, the support 52 and membrane 51 provide a fluid barrier between the mud that has flowed through the ports 50, and the inside of the support 52.
The support 49 also has pressure communication ports 53 which allow fluid communication between the inside of the support 49 and the rest of the motor subassembly 25 interior. As previously noted, the inside of the motor subassembly 25 is filled with a lubrication liquid; this liquid is contained inside the pulse generator motor housing 49 by a primary rotary seal 54 which provides a fluid seal between the driveshaft 24 and the pulse generator motor housing 49.
More particularly, the downhole end of the motor subassembly 25 comprises an end cap (not shown) with a bore for allowing the drive shaft 24 to extend therethrough. The end cap serves to cap the driveshaft end of the pulse generator motor housing 49 and keep the primary seal 54 in place. The primary seal 54 is seated in an annular shoulder at the downhole end of the pressure compensated housing 49.
As is known in the art, the membrane 51 can flex to compensate for pressure changes in the drilling mud and allow the pressure of the pressure compensated liquid to substantially equalize with the pressure of the drilling mud.
Electronics Subassembly
Referring now to
The D&I sensor module 100 comprises three axis accelerometers, three axis magnetometers and associated data acquisition and processing circuitry. Such D&I sensor modules are well known in the art and thus are not described in detail here.
The drilling conditions sensor module 102 include sensors mounted on a circuit board for taking various measurements of borehole parameters and conditions such as temperature, pressure, shock, vibration, rotation and directional parameters. Such sensor modules 102 are also well known in the art and thus are not described in detail here.
The main circuit board 104 can be a printed circuit board with electronic components soldered on the surface of the board. The main circuit board 104 and the sensor modules 100, 102 are secured on a carrier device (not shown) which is fixed inside the electronics housing 33 by end cap structures (not shown). The sensor modules 100, 102 are each electrically communicative with the main circuit board 104 and send measurement data to the encoder 105. The pressure transducer 34 is also electrically communicative with the main circuit board 104 and sends pressure measurement data to the encoder 105. The encoder 105 is programmed to encode this measurement data into a carrier wave using known modulation techniques. The controller 106 then sends control signals to the pulse generator to generate pressure pulses corresponding to the carrier wave determined by the encoder 105.
As will be described below, the memory 108 contains program code that can be executed by the controller 106 to carry out a number of methods that utilize the pressure measurement data. In particular, the pressure measurement data can be used in programmed methods for: predicting the life of the primary seal 54 in the motor subassembly 25, controlling pressure pulse amplitude in a dual height pressure pulse generator, and detecting a component failure which results in a change in pressure, such as venting from a battery failure.
Pressure Transducer and Feed Through Subassembly
Embodiments of the pressure transducer and feed through subassembly 29, 34 will now be described in detail with reference to
In each of the three embodiments, the feed through connector 29 is located between and electrically interconnects and fluidly separates the motor subassembly 25 and the electronics subassembly 28. Such feed through connectors 29 are known in the art, and a number can be adapted for use for the pressure transducer and feed through subassembly 29, 34. A suitable feed through connector 29, whether custom designed or adapted from commercially available products, has a body 80 which is pressure rated to withstand the pressures and pressure differentials inside the low-pressure electronics subassembly 28 (approximately atmospheric pressure) and inside the high-pressure motor subassembly 25 where pressures can reach about 20,000 psi, while still allowing electrical connectors to pass through the feed through connector 29. In alternate embodiments, the body 80 can be pressure rated to withstand up to 38,000 psi.
In the first embodiment of the pressure transducer and feed through subassembly 29, 34, the body 80 has a generally cylindrical shape with a first end (“high pressure end”) facing the inside of the motor subassembly 25 and a second end (“low pressure end”) facing the inside of the electronics subassembly 28. The body 80 is provided with circumferential shoulders and channels on which feed through O-ring seals 82, 83 are mounted. These feed through O-ring seals 82, 83 are provided to ensure a fluid seal is established between interiors of the electronics housing 33 and the pulse generator motor housing 49 when the feed-through 29 is in place.
The feed through connector 29 also comprises electrical interconnections which extend axially through the length of the body 80 and comprise pins which protrude from each end of the body 80; these electrical interconnections include electric motor interconnects 90 which transmit power and control signals from components in the electronics subassembly 28 and the pulse generator motor in the motor subassembly 25, as well as data from the pulse generator motor back to the components in the electronics subassembly 28. The pins of these interconnects 90 mate with electrical sockets (not shown) of the corresponding connectors of the pulse generator motor and power and control equipment.
At the high-pressure end of the body 80 is provided with a receptacle in which the pressure transducer 34 is seated. In this embodiment, the receptacle is located centrally in the high pressure end and has a depth that allows the pressure transducer 34 to be slightly recessed in the high pressure end of the body 80 with its detection surface facing outwardly from high pressure end of the body 80. A receptacle O-ring seal 84 (see
A C-shaped retention clip 92 is provided to secure the pressure transducer 34 in the receptacle. This retention clip 92 can be removed to allow the pressure transducer 34 and its connection pins 96 to be relatively easily removed from the feed through connector 29, e.g. for servicing or replacement without the need for soldering.
As can be seen in
Referring to
Referring to
Unlike conventional MWD telemetry tools which locate pressure transducers in a separate pressure probe or in complex housing which potentially exposes the transducer to a hostile environment, the pressure transducer 34 of this embodiment is located in a sealed protected environment and is exposed only to the clean lubrication liquid and not the drilling mud. Further, the pressure transducer and feed through subassembly 29, 34 eliminates the need for a separate pressure probe as well as the need for lengthy wire harnesses to connect conventional pressure transducers located in a remotely located pressure probe with the electronics of the MWD tool; also, since the pressure transducer occupies “dead space” inside the feed through connector 29, the overall length of the MWD tool 20 can be made shorter. Because the pressure transducer 34 of this embodiment is relatively rigidly fixed within the feed through connector 29, component fatigue and wear caused by vibration and movement which is a problem in systems using conventional wire-harness based connections is expected to be largely eliminated. Also, it is expected that the pressure transducer 34 of this embodiment will be more resistant to axial, lateral and torsional vibration experienced during drilling operations than pressure transducers mounted in a conventional pressure probe.
Because the pressure of the lubrication liquid corresponds to the pressure of the drilling mud at the pulse generator 30, the pressure transducer 34 can be used to measure the pressure pulses 5, 6 generated by the pulse generator 30. As will be discussed below in more detail, these measurements can be used to provide useful data for the operator to predict primary seal wear, detecting component failures, and operating the pulse generator 30 in an optimized and effective manner.
Although the pressure transducer and feed through subassembly 29, 34 of this embodiment is part of a MWD tool 20 that includes a dual height fluid pressure pulse generator 30, the pressure transducer and feed through subassembly 29, 34 can be used in other types of mud pulse MWD tools as well as certain types of EM MWD tools, including conventional single height fluid pressure pulse generators. Also, while the pressure transducer and feed through subassembly 29, 34 of this embodiment is located between the pulse generator motor and electronics subassemblies 25, 28, the pressure transducer and feed through subassembly 29, 34 can be located in other places of the MWD tool 20 where it may be useful to obtain pressure measurements.
Method of Detecting Component Failure Using Pressure Transducer Measurements
According to another embodiment of the invention and referring to
Referring to
Electrical interconnects 190 on the second feed through connector 129 electrically interconnect the battery terminal 116 with the electronic components inside the electronics subassembly 28 and with the pulse generator motor inside the motor subassembly 25, and provide power from the batteries to the pulse generator motor and electronic components and pressure measurement data from the pressure transducer 134 to the controller 106.
The second pressure transducer and feed through subassembly 129, 134 is mounted so that the pressure transducer 134 faces the first compartment 118 and can detect pressure changes inside the first compartment 118. The second pressure transducer 134 can be operated to continuously or periodically monitor the pressure inside the first compartment 118. The pressure inside the first compartment 118 is expected to significantly rise when one or more batteries 114 fails and vents its contents into the first compartment 118. Pressure measurement data from the second pressure transducer 134 is sent to the controller 106, which executes a battery monitor failure program stored on the memory 108. Referring now to
Method for Predicting Seal Life Using Pressure Transducer Measurements
According to another embodiment and referring to
The primary seal 54 will wear due to rotation from the drive shaft 24 and abrasion from drilling fluid. If the primary seal is not replaced after a certain period of time, the lubrication liquid inside the motor subassembly 25 will leak out. If enough lubrication liquid leaks out, drilling mud can leak in through the worn primary seal 54, which is detrimental to the operation of the motor, bearings and gearbox inside the motor subassembly housing.
The method for predicting primary seal life first comprises a calibration step which involves using the pressure transducer 34 to take a baseline pressure measurement P—baseline of the lubricating oil inside the motor subassembly 25 when the primary seal 54 is new and prior to downhole deployment; this baseline pressure measurement is logged in the memory 108 (step 150). This measurement is taken at surface at a known temperature. The lubricating oil pressure is typically purposely set in an initial assembly step at an overpressure that is slightly higher than atmospheric, i.e. Pbaseline>Patm. The MWD tool 20 is then inserted downhole and deployed in a drilling run; because of the pressure compensation device 32, the pressure of the lubricating oil will equilibrate with the downhole mud pressure (because the lubricating oil is generally incompressible, it is expected that the downhole pressure of the lubricating oil will be slightly higher than the mud pressure by an amount equal to the baseline overpressure).
After the run has been completed the MWD tool 20 is returned to surface, and the controller 106 then executes the next step of the method, which comprises reading the pressure measurement Poil from the pressure transducer 34 (step 152). The pressure measurement at surface can be temperature compensated for accuracy, but this may not be necessary if the threshold pressure has a large safety factor. This measurement is logged in the memory 108, and compared against a threshold pressure value Pthreshold which represents the lowest acceptable pressure before the primary seal 54 should be replaced (step 154); generally this threshold pressure is set to be slightly higher than atmospheric pressure. The value of Pthreshold can be set based on an operator's experience or by lab testing of primary seal wear and the lubricating oil pressure at which drilling mud will invade the motor subassembly 25, or by historical data collected from prior runs. If the pressure measurement is at or below Pthreshold then the controller 106 logs a unique “replace seal” flag in the memory 108 which can be read by an operator when the tool 20 is retrieved at surface using diagnostic equipment (not shown) connected to the controller 106 either wirelessly or by a hard line connection (step 156). Additionally, the controller 106 while downhole or at surface, can be programmed to send a unique “replace seal” signal indicating that the primary seal 54 should be replaced. The signal can be sent in the form of data communicated by a mud pulse telemetry transmission when the tool is downhole, or by some other measureable indicator such as a visual or audible indicator on the tool that can be seen or heard when the tool is retrieved at surface.
Optionally, the controller 106 can initiate a lockdown step (step 158) when the measured pressure Poil falls below the threshold value Pthreshold. The lockdown step can deactivate the MWD tool 20 thereby preventing the tool 20 from being inadvertently used before the primary seal 54 is replaced, and preventing a potential failure.
Method for Controlling Pressure Pulse Amplitude Using Pressure Transducer Measurements
According to another embodiment and referring to
As noted above, the pulse generator 30 comprises a rotor 60 and stator 40 combination which operates to generate pressure pulses 5, 6. Referring to
The following steps are performed when the controller 106 executes the program for controlling pressure pulse amplitudes. The controller 106 in an initiation step sends a control signal to the pulse generator motor to move the pulse generator 30 into each of the full flow (no pulse height state), intermediate flow (low pulse height state) and reduced flow (high pulse height state) configurations and reads the peak pressures from the pressure transducer 34 in each configuration, namely: Pno-pulse (to obtain a baseline measurement); Plow-pulse and Phigh-pulse (step 190). The controller 106 then determines the amplitudes of the pressure pulses in each of the low and high pulse height states by subtracting the read pressure measurements Plow-pulse and Phigh-pulse from the baseline measurement Pno-pulse. The controller 106 then compares the amplitude of the measured low amplitude pressure pulse Plow-pulse with the amplitude of a low amplitude reference pressure Pref-low stored in the memory 108; Pref-low can be selected to represent a sufficient amplitude that is expected to be required for the mud pulse telemetry signal to reach surface and be distinguishable by the surface operator. The controller 106 also compares the amplitude of the measured high amplitude pressure pulse Phigh-pulse with the amplitude of a high amplitude reference pressure Pref-high stored in the memory 108; Pref-high can be selected to represent an amplitude that is more than sufficient to transmit a telemetry signal to surface, and/or be so strong as to potentially damage or be detrimental to the drilling operation (step 191).
The controller 106 then determines which pressure pulse modes are available to transmit telemetry (step 192), as follows: When the amplitudes of Plow-pulse and Phigh-pulse are both greater than the amplitude of Plow-ref and less then than the amplitude of Phigh-ref the controller 106 determines that the conditions are suitable to operate the pulse generator 30 in either the high amplitude pulse mode only (steps 200-208) or the low amplitude pulse mode only (steps 210-218). When the amplitude of Plow-pulse is below the amplitude of Plow-ref and when the amplitude of Phigh-pulse is greater than the amplitude of Plow-ref but less than the amplitude of Phigh-ref, the controller 106 allows the pulse generator 30 to start operation only in the high amplitude pulse mode (steps 210 to 218). Conversely, when the amplitude of Phigh-pulse is greater than the amplitude of Phigh-ref and when the amplitude of Plow is higher than the amplitude of Plow-ref and less than the amplitude of Phigh-ref the controller 106 allows the pulse generator to start operation only in the low amplitude pulse mode (steps 200-208). When neither of the amplitudes of Plow-pulse and Phigh-pulse meet the reference thresholds, then the controller 106 does not allow the pulse generator 30 to operate in any mode, and logs an error message (step 193) onto the memory 108 or optionally sends the error message to surface by some other telemetry transmission means if available, e.g. by electromagnetic or acoustic telemetry if an electromagnetic or acoustic transmitter (neither shown) is part of the drill string.
When the controller 106 allows telemetry transmission in both high and low amplitude pulse modes, the controller can select to start transmitting telemetry in the low amplitude pulse mode. The controller 106 sends control signals to the pulse generator motor to operate the pulse generator 30 between the intermediate and full flow configurations (step 200) to generate a mud pulse telemetry signal. The method of encoding the telemetry data into a form suitable for mud pulse transmission using a single pulse mode is known as modulation and is well known in the art and thus not described in detail here.
While operating in the low amplitude pulse mode, the controller 106 periodically or continuously reads pressure measurements from the pressure transducer 34 (step 202). The controller 106 uses these pressure measurements to determine the amplitude of the low amplitude pressure pulse by subtracting Pno-pulse from Plow-pulse. The controller 106 compares the amplitude of the measured low amplitude pressure pulse with the amplitude of the low amplitude reference pressure Plow-ref (step 204). If drilling conditions have changed such that the amplitude of the measured pressure pulse is now below the amplitude of Plow-ref, the controller 106 switches to the high amplitude pulse mode by operating the pulse generator 30 between the reduced flow and full flow configurations (step 206); the high amplitude pressure pulse Phigh-pulse is designed to be larger in amplitude than the reference amplitude Plow-ref under a design range of operating conditions.
Instead of switching immediately to high-amplitude pulse mode when Plow-pulse is less than Plow-ref, the controller 106 can execute an optional step (not shown) to send a control signal to the pulse generator motor to extend the time period the rotor 60 is kept in the intermediate flow configuration during low amplitude pulse mode operation, thereby increasing the amplitude of the pressure pulse until the amplitude is strong enough for the telemetry signal to reach the surface, i.e. is greater than Plow-ref. In other words, the pulse generator 30 is held in the intermediate flow configuration for a time period that is longer than the default time period. If the amplitude of the pressure pulse even when operating under this optional step is less than Plow-ref, then the controller 106 switches to the high amplitude pulse mode (step 208).
While operating under the high amplitude pulse mode, the controller 106 sends control signals to the pulse generator motor to operate the pulse generator 30 between the reduced and full flow configurations to generate a mud pulse telemetry signal. As noted previously, the method of encoding the telemetry data into a form suitable for mud pulse transmission using a single pulse mode is known as modulation and is well known in the art and thus not described in detail here. The controller 106 continuously or periodically reads pressure measurements data from the pressure transducer 34 (step 206). If the amplitude of the measured pressure pulse is not strong enough even when the pulse generator 30 is operating in the high amplitude pulse mode (i.e. the amplitude of Phigh-pulse is less than Plow-ref), the controller 106 in an optional step (not shown) can send a control signal to the pulse generator motor to hold the rotor 60 in a reduced flow configuration for an extended time period that is a longer than the default time period (step not shown), thereby increasing the amplitude of the pressure pulse until the amplitude is strong enough to the telemetry signal to reach the surface.
When the pulse generator 30 is operating in the high amplitude pulse mode, the controller 106 compares the amplitude of the measured pressure Phigh-pulse to the high amplitude reference pressure Phigh-ref (step 208). If the drilling conditions have changed such that the amplitude of Phigh-pulse now exceeds Phigh-ref, then the controller 106 switches back to the low amplitude pulse mode by returning to step 200. If the amplitude of Phigh-pulse still remains below Phigh-ref then the controller 106 continues to operate the pulse generator 30 in the high amplitude pulse mode (step 206).
When the controller 106 has determined from the initiation step that the pulse generator 30 can be operated in both high and low amplitude pulse modes, the controller 106 can also start telemetry transmission using the high amplitude pulse mode (step 210), and continuously or periodically read pressure measurements from the pressure transducer 34 (step 212). The controller 106 continues to operate the pressure generator 30 in the high amplitude pulse mode so long as the amplitude of Phigh-pulse is below Phigh-ref and above Plow-ref. When the controller 106 determines that the amplitude of Phigh-pulse is below Plow-ref the controller in an optional step can hold the rotor 60 in the reduced flow configuration for the extended time period to increase the amplitude of the pressure pulse; if this step is not successful, the controller 106 can switch the pulse generator 30 to operate in the low amplitude pulse mode or stop operation and log an error message in the memory 108. When the controller 106 determines that the amplitude of Phigh-pulse exceeds Phigh-ref (step 214), the controller 106 will switch the pulse generator 30 to operate in the low amplitude pulse mode (step 216) and continuously or periodically read pressure measurements from the pressure transducer 34 (step 218). The controller 106 will continue to operate the pulse generator 30 in the low amplitude pulse mode until the amplitude of Plow-pulse falls below Plow-ref in which case the controller 106 switches back to operate in the high amplitude pulse mode (step 210).
Instead of arbitrarily starting the pulse generator 30 in the low amplitude or high amplitude pulse modes, the controller 106 can process data taken by the sensors in the MWD telemetry tool 20 or by other sensors in the BHA, to determine the drilling conditions and whether it is more favourable to start the telemetry transmission in the low amplitude or high amplitude pulse modes.
Alternatively, the controller 106 can omit executing the initiation step, and instead start telemetry transmission in one of the low amplitude or high amplitude pulse modes, and then switch to the other pulse mode when the pressure measurements taken during telemetry transmission indicate that the amplitude of the measured pressure pulses do not meet their threshold reference values.
As noted above, the telemetry data can include D&I and drilling condition data measured by the sensors in the MWD tool 20. Part of the telemetry data that is sent to the surface by the pulse generator 30 can also include the amplitudes of the pressure pulses generated by the pulse generator 30. This data can be compared to uphole measurements to determine pulse height losses (i.e. pressure pulses generated versus the pressures measured at surface, etc.); this data can be useful for properly modelling attenuation of pulses under given conditions.
By executing the program that carries out the method for controller pressure pulse amplitude, the MWD tool 20 can be an adaptive tool to flow variable conditions, such as depth, density and flow rate. The method provides a means for checking if the pressure pulse is too high or too low; the latter can cause damage to the rotor 60/stator 40 and lead to cavitation of the drilling mud through the pulse generator 30 because of the excessive pressure drop or change across the MWD tool 20, and the former can cause drive shaft 24 failure by increased tension on the drive shaft 24 or failure of other components such as bearings and keys due to excessive load. Execution of this program is also expected to increase reliability of mud pulse telemetry as the amplitude of the pulse is optimized for transmission to surface, i.e. the method ensures that the pulse amplitude is sufficiently strong to be decoded at surface.
While the present invention is illustrated by description of several embodiments and while the illustrative embodiments are described in detail, it is not the intention of the applicants to restrict or in any way limit the scope of the appended claims to such detail. Additional advantages and modifications within the scope of the appended claims will readily appear to those sufficed in the art. The invention in its broader aspects is therefore not limited to the specific details, representative apparatus and methods, and illustrative examples shown and described. Accordingly, departures may be made from such details without departing from the spirit or scope of the general concept.
| Number | Name | Date | Kind |
|---|---|---|---|
| 3302457 | Mayes | Feb 1967 | A |
| 3309656 | Godbey | Mar 1967 | A |
| 3764968 | Anderson | Oct 1973 | A |
| 3958217 | Spinnler | May 1976 | A |
| 3982224 | Patton | Sep 1976 | A |
| 4351037 | Scherbatskoy | Sep 1982 | A |
| 4641289 | Jürgens | Feb 1987 | A |
| 4734892 | Kotlyar | Mar 1988 | A |
| 4771408 | Kotlyar | Sep 1988 | A |
| 4785300 | Chin et al. | Nov 1988 | A |
| 4830122 | Walter | May 1989 | A |
| 4847815 | Malone | Jul 1989 | A |
| 4914637 | Goodsman | Apr 1990 | A |
| 4953595 | Kotlyar | Sep 1990 | A |
| 4979577 | Walter | Dec 1990 | A |
| 5073877 | Jeter | Dec 1991 | A |
| 5079750 | Scherbatskoy | Jan 1992 | A |
| 5182730 | Scherbatskoy | Jan 1993 | A |
| 5182731 | Hoelscher et al. | Jan 1993 | A |
| 5215152 | Duckworth | Jun 1993 | A |
| 5237540 | Malone | Aug 1993 | A |
| 5249161 | Jones et al. | Sep 1993 | A |
| 5316610 | Tamaki et al. | May 1994 | A |
| 5390153 | Scherbatskoy | Feb 1995 | A |
| 5396965 | Hall et al. | Mar 1995 | A |
| 5583827 | Chin | Dec 1996 | A |
| 5586083 | Chin et al. | Dec 1996 | A |
| 5586084 | Barron et al. | Dec 1996 | A |
| 5636178 | Ritter | Jun 1997 | A |
| 5740126 | Chin et al. | Apr 1998 | A |
| 5740127 | Van Steenwyk et al. | Apr 1998 | A |
| 5787052 | Gardner et al. | Jul 1998 | A |
| 5950736 | Goldstein | Sep 1999 | A |
| 6016288 | Frith | Jan 2000 | A |
| 6097310 | Harrell et al. | Aug 2000 | A |
| 6105690 | Biglin, Jr. et al. | Aug 2000 | A |
| 6219301 | Moriarty | Apr 2001 | B1 |
| 6414905 | Owens et al. | Jul 2002 | B1 |
| 6453747 | Weise et al. | Sep 2002 | B1 |
| 6469637 | Seyler et al. | Oct 2002 | B1 |
| 6626253 | Hahn et al. | Sep 2003 | B2 |
| 6714138 | Turner et al. | Mar 2004 | B1 |
| 6750783 | Rodney | Jun 2004 | B2 |
| 6850463 | Winnacker | Feb 2005 | B2 |
| 6867706 | Collette | Mar 2005 | B2 |
| 6898150 | Hahn et al. | May 2005 | B2 |
| 6932154 | Zillinger | Aug 2005 | B2 |
| 6970398 | Lavrut et al. | Nov 2005 | B2 |
| 6975244 | Hahn et al. | Dec 2005 | B2 |
| 7138929 | Jeffryes et al. | Nov 2006 | B2 |
| 7145834 | Jeter | Dec 2006 | B1 |
| 7180826 | Kusko et al. | Feb 2007 | B2 |
| 7230880 | Lehr | Jun 2007 | B2 |
| 7250873 | Hahn et al. | Jul 2007 | B2 |
| 7280432 | Hahn et al. | Oct 2007 | B2 |
| 7319638 | Collette | Jan 2008 | B2 |
| 7327634 | Perry et al. | Feb 2008 | B2 |
| 7330397 | Ganesan et al. | Feb 2008 | B2 |
| 7367229 | Engstrom | May 2008 | B2 |
| 7400262 | Chemali et al. | Jul 2008 | B2 |
| 7405998 | Webb et al. | Jul 2008 | B2 |
| 7417920 | Hahn et al. | Aug 2008 | B2 |
| 7468679 | Feluch | Dec 2008 | B2 |
| 7552761 | Moriarty | Jun 2009 | B2 |
| 7564741 | Pratt et al. | Jul 2009 | B2 |
| 7719439 | Pratt et al. | May 2010 | B2 |
| 7735579 | Gopalan et al. | Jun 2010 | B2 |
| 7808859 | Hahn et al. | Oct 2010 | B2 |
| 7839719 | Dopf et al. | Nov 2010 | B2 |
| 7881155 | Close | Feb 2011 | B2 |
| 8151905 | Song | Apr 2012 | B2 |
| 8174929 | Camwell et al. | May 2012 | B2 |
| 8203908 | Pratt et al. | Jun 2012 | B2 |
| 8251160 | Gopalan et al. | Aug 2012 | B2 |
| 8364406 | Gleitman | Jan 2013 | B2 |
| 9714569 | Logan | Jul 2017 | B2 |
| 20050200498 | Gleitman | Sep 2005 | A1 |
| 20090038851 | Camwell et al. | Feb 2009 | A1 |
| 20090280912 | Buchanan et al. | Nov 2009 | A1 |
| 20100212963 | Gopalan et al. | Aug 2010 | A1 |
| 20110005835 | Li | Jan 2011 | A1 |
| 20110168445 | Patwa et al. | Jul 2011 | A1 |
| 20110169655 | Close et al. | Jul 2011 | A1 |
| 20120085583 | Logan et al. | Apr 2012 | A1 |
| 20120127829 | Sitka | May 2012 | A1 |
| 20120195442 | Villemoes et al. | Aug 2012 | A1 |
| Number | Date | Country |
|---|---|---|
| 1 228 909 | Nov 1987 | CA |
| 1 229 998 | Dec 1987 | CA |
| 2 506 808 | Oct 2010 | CA |
| 2 551 316 | Jan 2012 | CA |
| 2 855 940 | Jun 2013 | CA |
| 2457175 | May 2011 | GB |
| 9405893 | Mar 1994 | WO |
| 2005084281 | Sep 2005 | WO |
| 2006130606 | Dec 2006 | WO |
| 2007033126 | Mar 2007 | WO |
| 2009033146 | Mar 2009 | WO |
| 2010138961 | Dec 2010 | WO |
| 2012027245 | Mar 2012 | WO |
| 2012027633 | Mar 2012 | WO |
| 2012130936 | Oct 2012 | WO |
| 2012145637 | Oct 2012 | WO |
| 2014071514 | May 2014 | WO |
| Number | Date | Country | |
|---|---|---|---|
| 20170284194 A1 | Oct 2017 | US |
| Number | Date | Country | |
|---|---|---|---|
| 61738285 | Dec 2012 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 14652445 | US | |
| Child | 15628473 | US |
