Closed loop flow controlled bypass flow diverter

Abstract

A drilling system includes a drill string having a flow of drilling fluid and a bypass sub in the drill string. A flowrate of the drilling fluid is monitored by a flow sensor downstream of the bypass sub, and a portion of the drilling fluid is diverted from the bypass sub when the flowrate exceeds a designated amount. The drilling fluid is diverted by opening a valve in the bypass sub, and adjusting the amount open of the valve controls a flowrate of the portion being diverted. A flow controller in communication with the flow sensor initiates commands for opening the valve and adjusting its amount open.

Description

Attomey Docket No.: 0005355.000245 (65DRL-510343-WO-2)PCT PATENT APPLICATIONCLOSED LOOP FLOW CONTROLLED BYPASS FLOW DIVERTERInventor: Volker PETERSBACKGROUND OF THE INVENTION1. Field of Invention

[0001] The present disclosure relates to controlling a bypass flow from a drill string based on a flowrate.2. Description of Prior Art

[0002] Production of hydrocarbons from subterranean formations typically involves forming a wellbore into the formation that intersects a reservoir where the hydrocarbons are trapped. Drilling systems are commonly used for forming the wellbores, which are generally made up of a drill string with a drill bit on its lower end for excavating through the formation. Drill strings are usually a formed by end to end connection of a number of pipe joints, and are rotated by a top drive or rotary table on surface, which in turn rotates the drill bit. In some drilling systems the drill bit is rotated by a mud motor that is disposed in the drill string. The bottom end of the drill bit usually includes a type of cutting element to scrape against the formation and break away rock fragments or cuttings to deepen the wellbore. The rotation along with adding weight onto the bit, provides the excavating force necessary to fracture the rock and form the cuttings. Pressurized drilling fluid is directed to a bore inside the drill string, where it is directed to the drill bit. The fluid exits the drill bit through nozzles on its lower surface, and then flows back to surface in an annulus between the drill string and walls of the wellbore. The cuttings become entrained in the drilling fluid circulating uphole and are removed from within the wellbore.

[0003] A number of operational criteria require that the flowrate of the drilling fluid be within a designated range. For example, inadequate or excessive fluid flow in the drill string can result in-1-IM-#10838087.2damage to the formation, a mud motor in the drilling system, or result in a drill string being stuck inside the wellbore. Flow control is often achieved with a bypass that diverts a portion of the drilling fluid from inside the drill string to the annulus uphole of the drill bit. Bypassed fluid from the inside of the drill string to the annulus is often required to enhance the transport of cuttings to the surface. Known bypass systems rely on monitoring pressure drops in the fluid, which can be misleading when pressure drops become dynamic.-2-IM-#10838087.2SUMMARY OF THE INVENTION

[0004] Disclosed herein is an example of a method of operating a drilling system that includes flowing drilling fluid in a drill string disposed in a wellbore, monitoring a flowrate of the drilling fluid, and controlling a flowrate of the drilling fluid flowing through the drill string based on the step of monitoring. Controlling a flowrate of the drilling fluid optionally includes diverting a portion of the drilling fluid from within the drill string, further optionally, the portion of the drilling fluid is diverted from the drill string at a bypass location that is upstream of a bottom hole assembly, yet further optionally a bypass flow is formed by the step of diverting and wherein a flowrate of the bypass flow is adjusted so that a flowrate of drilling fluid flowing between the bypass location and bottom hole assembly is substantially equal to a designated flowrate. In a further alternative, the bypass flow flowrate is controlled by actuating a valve in the bypass sub. The method further optionally includes rotating a drill bit on a lower end of the drill string to excavate the wellbore to a greater depth within a surrounding formation, pressurizing the drilling fluid, and injecting the drilling fluid into an upper end of the drill string so that drilling fluid exiting the drill bit carries cuttings uphole that are formed by excavating the formation. In an embodiment, a turbine is disposed in a path of the drilling fluid flowing in the drill string and the step of monitoring a flowrate of the drilling fluid includes sensing a rotation of the turbine. Electricity is optionally generated from the rotation of the turbine. In examples, a flowrate of the bypass flow remains substantially constant during a time period when pressure in the drilling fluid changes. The method optionally includes creating telemetry pulses with the bypass flow.

[0005] Also disclosed is an example of a drilling system that includes a drill string in a wellbore, and a bypass sub in the drill string that controls an amount of drilling fluid flowing through the drill string in response to a flowrate of drilling fluid sensed in the drill string. In an example, the bypass sub is selectively configured between a bypass mode and a flowthrough mode, where when in the bypass mode a portion of a drilling fluid flowing inside the drilling string is diverted to outside of the drill string and when in the flowthrough mode the flowrates of drilling fluid upstream and downstream of the bypass sub are equal. Further optionally included is a bypass valve in the bypass sub, the bypass valve made up of an annular valve body having a downstream end and an annular valve plug having an upstream end that registers with the valve body downstream end when the bypass sub is in the flowthrough mode, alternatively, the valve body and valve plug are selectively moveable away from one another to move the upstream and downstream ends out of-3-IM-#10838087.2registration and define an opening in the bypass valve. In an example, selectively moving the valve body and valve plug closer to or further away from one another creates a variable resistance across the opening for drilling fluid flowing through the drill string. In this example, the variable resistance creates a proportional relation between bypass flow rate and valve position at a certain differential pressure across the opening (between bore and annulus at the bypass opening position). A bypass port is optionally added, which is formed radially through a sidewall of the bypass sub, where the bypass port is in communication with drilling fluid flowing through the drill string across the opening in the bypass valve, hr examples a flow controller is included that is configured to adjust relative movement between the valve body and valve plug based on a flowrate of drilling fluid sensed in the drill string upstream of the bypass sub and / or downstream of the bypass sub. In one example, the bypass controller adjusts the relative position between the valve body and valve plug to maintain the flowrate downstream of the bypass sub between certain thresholds. Further exemplary, the thresholds can be adjusted from the surface by commands sent to the bypass sub. e. g„ by variations of pressure, flow or rotation. Examples of the drilling system include a flow sensor in the drill string that is in communication with the flow controller, and optionally include an actuator in the drill string coupled to one of the valve body or valve plug so that relative movement occurs between the valve body and valve plug by energizing the actuator. Examples of the actuator include a linear drive motor and an elongated rod connects the linear drive motor to a downstream end of the valve plug, and where a valve exit is formed through a sidewall of the valve plug adjacent to where the rod connects to the downstream end.

[0006] Another example of a drilling system is disclosed which includes a drill string in a wellbore, and a bypass sub in the drill string that, in response to a pressure of drilling fluid sensed in the annulus between the drill string and the wellbore, controls an amount of drilling fluid flowing through the drill string.-4-IM-#10838087.2BRIEF DESCRIPTION OF DRAWINGS

[0007] Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which:

[0008] FIG. 1 is an elevational partial sectional view of an example of a drilling system forming a wellbore.

[0009] FIG. 2 is a schematic sectional view of an example of a drill string in the drilling system of FIG. 1.

[0010] FIG. 3 is a partial sectional view of an alternate embodiment of the drill string of FIG. 2.

[0011] FIGS. 4A-4C are side sectional views of an example of operation of a bypass sub in the drill string of FIG. 3.

[0012] While subject matter is described in connection with embodiments disclosed herein, it will be understood that the scope of the present disclosure is not limited to any particular embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents thereof.-5-IM-#10838087.2DET AILED DESCRIPTION OF INVENTION

[0013] The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes + / - 5% of a cited magnitude. In an embodiment, the term “substantially” includes + / - 5% of a cited magnitude, comparison, or description. In an embodiment, usage of the term “generally” includes + / - 10% of a cited magnitude.

[0014] It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation.

[0015] Shown in a side partial sectional view in FIG. 1 is an example of a drilling system 10 forming a wellbore 12 in a subterranean formation 14. Drilling system 10 includes an elongated drill string 16, which is made up of a pipe string 18 with an inner bore 19 and a bottomhole assembly (“BHA”) 20 mounted on a lower end of the string 16. Bottomhole assembly 20 includes an outer housing 22 and on its lowermost end is a drill bit 24 for excavating in the formation 14 to form wellbore 12. Included in this example is a mud motor 26 within the housing 22 of bottomhole assembly 20. On drill string 16 and spaced uphole of the bottomhole assembly 20 is an example of a bypass sub 28, which as described in more detail below, provides a means for diverting a portion of drilling fluid (or drilling mud) flowing downhole inside pipe string bore 19 back upwards and in an annulus 29 between drill string 16 and sidewalls of wellbore 12.

[0016] A mud pit 30 is shown on surface and outside wellbore 12, which contains a reserve of drilling fluid for use when drilling wellbore 12. A mud pump 32 is shown for pressurizing the drilling mud that when discharged flows through a line 34 to a Kelly 36 suspended within a derrick 38 that mounts over an opening of the wellbore 12. A rotary table 40 is schematically illustrated-6-IM-#10838087.2mounted on derrick 38 and for providing rotational force to the drill string 16. Also over wellbore 12 is a wellhead assembly 42 fitted with a blowout preventer. An optional controller 44 is schematically shown outside wellbore 14 for providing commands to and / or receiving data signals from devices inside wellbore 12. Communication with controller 44 and downhole is via communications means 46, examples of which include hardwired, fiber optic, and wireless.

[0017] In FIG. 2 is a side sectional view of an example of a portion of the drill string 16 with the bypass sub 28. In this example, bypass sub 28 is shown having an outer housing 48, which is an annular member with a bore 50 extending axially within. Inside bore 50 is a bypass valve 52 for controlling drilling fluid flow, which includes a lateral bypass port 54 for selectively diverting a bypass flow FB outside of the bypass sub 20 and into the surrounding annulus 29. For purposes of discussion herein, the drilling fluid flowing downhole and within pipe string bore 19 is referred to as a main flow FM and the amount of flow that is not being diverted to outside of the bypass sub 28 is referred to as fluid downhole FDH. Downhole of the bypass valve 52 is a flow sensor 56 for sensing fluid downhole FDH flowrate. In alternatives the flow sensor 56 or an additional one is located upstream of the bypass sub 28. The flow sensor 56 of FIG. 2 is shown as an orifice meter, alternatives of flow sensor 56 include a Venturi-type flow sensor, a turbine-type flow sensor, a vortex flow meter, a mag meter, an ultrasonic flow meter, a mass flow meter, and combinations. Connected to flow sensor 56 is a flow controller 58, which is in communication with the bypass valve 52 via communication means 60. Flow controller 58 of FIG. 2 is equipped with programmable software for controlling operation of the bypass valve 52. Embodiments exist in which bypass valve 52 operation is based upon a sensed flowrate (volumetric or mass) of fluid downhole FDH flowing through the bore 50 of bypass sub 28. An advantage of controlling the bypass valve 52 based on fluid flowrate is that the bottomhole assembly 20 consistently receives a designated flow of drilling fluid so that operational requirements are met. As noted above, previously known control means for delivering fluid downhole relied on pressure feedback, which could be skewed due to the variations of dynamic pressure losses that may occur in a drilling string or drilling operation.

[0018] In FIG. 3, an alternate example of drill string 16A is shown in a side sectional view. In this example, the bypass valve 52A is shown made up of a valve body 62A and a valve plug 64A. Valve plug 64A and valve body 62 A are both annular members and moveable with respect to one another along an axis Ai6A of the drill string 16 A. A bore 66 A extends axially through the valve-7-IM-#10838087.2body 62A and valve plug 64A. A downstream end of the valve plug 64A is closed and openings are formed through the sidewalls of the valve plug 64A to form a valve exit 68A. An elongated actuator rod 70 A attaches to an outer surface of the downhole end of valve plug 64A and adjacent the valve exit 68A. Actuator rod 70A, also referred to herein as a valve stem, is shown substantially parallel with axis Ai6A, and has an end opposite the valve plug 64A that couples with a drive system 72A housed within the housing 48A. In an alternative, drive 72A is a linear drive system for converting rotational motion from an adjacent motor 74A into linear motion to displace the actuator rod 70A. A shaft 76A is illustrated connecting the motor 74A with linear drive 72A. In this example, motor 74A is in communication with a controller 78A via communication means 80A. In the example of FIG. 3, the controller 78A is within housing 48A and operates in response to signals from the flow controller 50A, which is shown mechanically coupled with the flow sensor 56A. Sensor 56A of FIG. 3 is a turbine-type meter and which rotates in response to the flow of fluid downhole FDH and over the blades of the turbine. In alternatives, the controller 58A includes a generator (not shown) for converting the rotational energy of the turbine blades of flow sensor 56A into electrical energy. Also shown within the drill string 16A is a mud motor 82A downstream of the flow sensor 56A that in the example shown converts energy of the flow of fluid downhole FDH into a rotational force, such as for driving a drill bit 24 (FIG. 1) within the bottomhole assembly 20.

[0019] Shown in a side sectional views in FIGS. 4A - 4C are examples of operation of the bypass valve 52A, which is selectively changeable between a closed configuration with no diverted flow and open configurations with varying amounts of diverted flow. An example of a closed configuration is shown in the example of FIG. 4A. In the closed configuration valve 52A is in a flow-through mode in which substantially all of main flow FM passes through valve 52A to the valve exit 68A, then flows downstream into the bore 50A where it flows around the actuator rod 70 A. In the embodiment shown, an outer diameter of valve body 62 A reduces on its end facing valve plug 64A to define a downstream end 84A. An end of the valve plug 64A adjacent the valve body 62A defines an upstream end 86A, which has a profile along its inner surface complementary to the outer surface of downstream end 84A. In the flow-through mode, the downstream end 84A inserts into upstream end 86A and selectively forms a sealing interface 87A between the valve body and plug 62A, 64A. Sealing interface 87A is a barrier to fluid communication to block main flow FM in bore 66A from passing to bypass port 54A and guides substantially all of main flow FM-8-IM-#10838087.2through the valve 52A so that main flow FM and fluid downhole FDH flowrates are substantially equal when valve 28A is in the flowthrough configuration. In this example, flowrate FR being the flowrate exiting the drill bit and returning back in the annulus between the BHA and the bypass sub. FR quals FDH but is directed uphole. Annular flow uphole the bypass sub includes the bypassed portion FB.

[0020] Referring now to FIG. 4B, valve 52A is selectively reconfigured into an open configuration by moving the valve plug 64A axially away from the valve body 62A. When in the open configuration the sealing interface 87 A is removed and an opening 88A forms between the downstream and upstream ends 84A, 86A. The opening 88A enables communication between bore 66A and bypass port 54A and a bypass flow FB is diverted from within bore 66A and into annulus 29A. An annular bulkhead 90A is formed between the outer surface of the valve plug 64A and inner surface of housing 48A, which blocks backflow of any fluid downhole FDH between an annulus 92 A surrounding the valve plug 64 A to the bypass port 54A. In this example, the annular bulkhead 90A works as a seal blocking flow FDH between the annulus 92A and the bypass port 54A, while allowing reciprocating movement of the valve plug 64A. The differential pressure between the annulus 92 A and the bypass port 54A can reach significant levels. This differential pressure depends on a) the distance between bypass sub 28 and BHA 20, flow cross sections along this distance internally at the drill string 16 as well as externally and back uphole within the annulus 29A, b) flow restrictions through the BHA 20, c) differential pressure across a drilling mud motor 26, d) restrictions caused by the nozzles inside the drill bit 24, and e) all other flow restrictions from the bypass sub and back through the annulus towards the flow bypass port 54A. With those restrictions, this differential pressure can reach as much as several hundred bar, and example differential pressures are in the range of from about 50 bar to about 500 bar. As illustrated in FIG. 4C valve 52A is reconfigured from its position in FIG. 4B with valve plug 64A moved axially uphole and towards valve body 62 A to reduce the size of opening 88 A and lower the flowrate of bypass flow FB being diverted to bypass port 54A from that of FIG. 4B. In the open configurations shown in FIGS. 4B and 4C, valve 52A is in a controlling / diverting mode. The open configuration of the valve 52A is not limited to those shown in FIGS. 4B and 4C, but includes any embodiment in which body 62A and plug 64A are spaced apart (at any distance) from one another to form opening 88A. At the comparably high-pressure differential as described above, the diverted flow is a function of the design of the body 62A and plug 64A and corresponding flow restriction due-9-IM-#10838087.2to axial positioning. It will be appreciated that small axial distance / opening between body 62A and plug 64A can cause significant bypass flow through the bypass port 54A, if differential pressure is high. In examples, positioning of the linear drive 72A is precise and accurate and adjustable to adjust the bypass flow through the bypass port 54A.

[0021] In a non-limiting example of operation, the valve 52A is selectively set into a closed configuration, or one of the many open configurations, so that flowrate of fluid downhole FDH or flowrate of bypass flow FB is / are at least at a minimum designated flowrate to satisfy operational demands of the drilling system 10 (FIG. 1). Examples of the operational demands of the drilling system 10 include a flowrate of fluid downhole FDH reaching mud motor 82A (FIG. 3) at a threshold flowrate and pressure adequate to drive a bit in the bottomhole assembly 20. Other examples of operation demands include static head pressure requirements and a recirculation flowrate back uphole within the annulus 29A. Further operational flowrate demands are attributed to an operating flowrate range of the BHA 20. In an alternative, the flowrate FDH actuates a turbine alternator system as part of the BHA 20 that supplies electrical energy to the BHA 20. Further optionally, included with the BHA 20 is a Mud Pulse Telemetry systems to communicate information from a downhole location to the surface. In this alternate example, the alternator and I or mud pulse telemetry system is not operational below a minimum flowrate FDH. There is also an operating limit for a maximum flowrate allowed to pass alternator and / or mud pulse telemetry systems to prevent premature damage or overload.

[0022] Another example operating scenario for controlling the flowrate FDH between certain minimum and maximum parameters is in response to different well control situations. In examples in which excessive flow FDH fractures the wellbore 12 due to additional pressure in the annulus 29 from the higher flowrate FR returning from the BHA 20 and drill bit 24. Examples for minimum requirements for flowrate FR include hole cleaning demands (cuttings transport) as well as demands for minimum fluid pressure to avoid collapse of wellbore 20. In an alternative, the configuration of the valve 52A is set in response to sensing a flowrate of fluid downhole FDH with flow sensor 56, and using flow controller 58 (FIG. 3) and controller 78A to energize motor 74A, which drives actuator 70A that in turn positions valve plug 64A adjust the flowrate of fluid downhole FDH or bypass fluid FB to meet operational demands of drilling system 10 or demands for wellbore stability and cleaning as described above. Alternatives include adjusting other flow parameters, such as fluid pressure of any of the flows discussed herein, and / or the composition of-10-IM-#10838087.2the fluid making up the flow. Optionally, flowrate uphole of valve 52A is sensed for determining a real time flow of fluid in the drill string 16A. It is within the capabilities of those skilled in the art to identify designated fluid flowrates meeting the operational demands of drilling system 10 and the configurations of valve 52A satisfying those demands. In the example of FIG. 4B, a command is issued from the controller 58A to direct the controller 78A and motor 74A to energize and cause operation of the drive 72A to move shaft 70A in the direction of arrow A?OA which moves the valve plug 64A to create opening 88A. As shown in FIG. 4C, arrow A70A is directed in the opposite direction to move the plug 64A towards body 62A and reduce the size of opening 88A.

[0023] In a non-limiting example of use bottomhole assembly 20 (FIG. 2) requires a downhole flow FDH of 2,500 liters per minute to flow through the drill bit 24. In this example, wellbore 12 at an upper end has a casing (not shown) with a large diameter require hole cleaning so that mud pumps 32 are set to deliver fluid at 3,500 liters per minute. Here, the bypass sub 28 is position proximate an upper portion of the wellbore 12. Control of the valve 52 is based on maintaining a sensed flow through the flow sensor 56 to be at 2,500 liters per minute. In the example of FIG. 3 and sensor 56A is a turbine, sensing a fluid flowrate includes determining a rotation of the turbine in response to a flow of fluid across the turbine. Any difference in flow uphole and downhole of the bypass sub 28 is controlled by diverting flow in the form of bypass flow FB from the bypass sub 28 into the surrounding annulus 29. This creates a closed loop controlled operation. If, in this configuration the downhole motor 82A is loaded with a higher differential pressure from, e. g„ higher weight on bit (“WOB”), the flow through the bypass port 54A increases as a response to the larger differential pressure across the bypass port 54A (and caused by the higher motor differential). Without regulating the bypass port 54A like in prior art systems, the flowrate FDH of 2,500 liters would drop to a lower value. In some circumstances this lowered flowrate can cause undesirable conditions for the wellbore 12 (FIG. 1), cuttings transport or would be below the required flow for the BHA 20 to function properly as described above. With the disclosed closed loop system, the sensor 56, 56A senses a too low rate of the flow FDH and adjusts the bypass port 54A (further closes) until the required flow FDH is re-established.-l i¬IM-#10838087.2

[0024] In a non-limiting example, the controller 78A is programmed at the surface prior to running in the wellbore 12, and so that a flow FDH is held at a certain level between an upper and a lower threshold, where these thresholds are adjustable, e. g„ based on the BHA 20 limitations as described above (mud pulse telemetry limits and I or turbine rpm limits). In another example, the operating mode can be programmed that the bypass sub 28A fully closes the valve exit 68A if the measured flowrate FDH is below a certain threshold. In another example the valve exit 68A is fully opened if the measured flowrate FDII is below a certain threshold. Embodiments exist in which these modes depend on actual expected hole cleaning properties or cuttings transport demands.

[0025] In another non limiting example, the bypass sub 28A (FIG. 3) is additionally equipped with an annular pressure sensor 85A monitoring the downhole pressure in the annulus 29A and in communication with the controller 78 A. In an alternative in which the pressure sensor 85 A measures a well control event like a pressure drop event, the controller 78A automatically adjusts the position of body 62A with respect to plug 64A, which varies flow through the bypass ports 54A in order to mitigate the well control event. In one optional scenario, the body 62A is moved with respect to plug 64A into a fully opened position to allow maximum flow through the bypass ports 54A. This operating mode allows for circulation through the bypass ports 54A at a comparably low pressure and above the drilling BHA 20 until the well control event is mitigated. In alternatives, bypass sub 28 remains in an open position while readings at the annular pressure sensor 85A are within a certain range, even if the pumps are shut off.

[0026] In yet another example programmed operating mode, the bypass ports 54A remain in a closed position after the flow is brought up for a preprogrammed duration, even if the threshold for the operating flow FDH is crossed, which is beneficial as data transmission from the BHA 20 to the surface is not disturbed, for instance during transmission of a directional survey, where data transmission must be without errors that cannot be removed during data aggregation and evaluation at surface. After a preprogrammed period, like e. g., 5 minutes, the bypass sub 29A operates in the normal bypass mode and bypasses surplus fluid beyond the preprogrammed flow FDH through the bypass opening.

[0027] In another example, the bypass sub 28A is configured to receive data (commands) from the surface. Such data and commands in this example are used to switch from one operating mode to another, like e. g. , fully opening the bypass ports 54A for a certain purpose (well control, cuttings-12-IM-#10838087.2transport, fluid exchange, tripping in the hole or tripping out of the hole or others) or fully closing the bypass sub 29 A, regardless of current measured flowrate FDH. In another example of an operating mode, such as adjusting the value of FDH where the bypass ports are opened or thresholds or timings when the bypass sub 28A performs a certain function is adjusted by sending commands from the surface. Commands from the surface, in this example are sent by variations of the flowrate FM that is injected downhole from the pumps. Optionally, variations of FM are detected by the sensor 56A, sensing a fluid flowrate by determining a rotation of the turbine. Certain variations over time of the flow FM encode the data that is communicated from the surface to the bypass sub 28A. In examples, the flow variation pattern is received as a bit stream from the turbine rpm variation as detected from the controller in communication with the sensor (turbine I alternator). Such commands are optionally sent at a flowrate FM below the threshold where typically the bypass ports 54A would be opened to be detected by the sensor 56A without interference of any bypassed flow through ports 54A that would reduce the sensor reading. In examples in which the commands are communicated from the surface via flow FM to the bypass sub 28A at a full operating flow, including the bypass flow FB, the bypass sub 28A is optionally programmed with a delay to react on variations of flow FM (dead time). If such delay is long enough, typically longer than the flow variation, the commands are optionally received by the controller 78 A even if the flow FM is beyond the controlled Flow FDH.

[0028] In yet another embodiment, the bypass sub 28A is used to send data to the surface. Which in examples is important to obtain a confirmation from the bypass sub 28A that a certain operating mode is executed or changed. In alternatives, such data is coded at the controller 78A and sent to the surface via variations of bypass flow or variations of pressure (of flow FM). Such variations of pressure or flow are alternatively executed by selectively and partially opening and closing the position of body 62A with respect to plug 64A and thus adjusting the flow through the bypass ports 54A in a defined pattern and with defined rates.

[0029] Examples of other data transmitted from the bypass sub 28A includes sensor data as measured at the location of the bypass sub 28A by any kind of attached sensor element, including but not limited to temperature, pressure, inclination, azimuth, gamma, resistivity, torque, axial load, vibration, rotary speed and others. Alternate embodiments include tools that are typically used inside a drilling BHA, which are attached and in communication to the bypass sub 28S, thus forming a second BHA (not shown) at a second location apart from the primary drilling BHA.-13-IM-#10838087.2Such drilling tools are optionally connected by a modular connection (not shown) at an end of the bypass sub 28A, including a physical wire connection to transfer power and data from and to the bypass sub. Examples of such drilling tools include, but are not limited to, a resistivity tool, a directional tool, a gamma measurement tool, a porosity measurement tool, a dynamics and strain measurement tool, combinations, and others. In examples, the tools are powered by the turbine alternator device within the bypass sub 28A. The use as a mud pulser at such above BHA or stand alone to transmit status data or information from the bypass sub sensors, creates so called negative pulses by selectively opening and closing the bypass channel in sequences. In examples in which continuous communication is desired, at surface, negative pulses are differentiated from normal positive pulses typically sent from the drilling BHA. With that, both data streams are optionally sent and received in parallel.

[0030] In yet another embodiment, the bypass sub 28A is used as a MWD mud pulser for a BHA 20A that is in close proximity to the bypass sub 28 A and features a communication link (e. g., a wired connection) from the tools within the BHA 20 (like e. g., directional sensors, gamma sensors, rotary steerable tools and others) to the bypass sub 28A. For such a setup, the bypass sub 28A is optionally utilized for two purposes at a time. First use includes the function of a mud pulse telemetry valve as part of an MWD, including power supply from the turbine alternator device within the bypass sub and second use includes the function as a bypass sub, opening flowrate above the BHA 20 if a certain threshold FM exceeds the preset threshold for FDH.

[0031] The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.-14-IM-#10838087.2

Claims

CLAIMSWhat is claimed is.

1. A method of operating a drilling system comprising: flowing drilling fluid in a drill string disposed in a wellbore; monitoring a flowrate of the drilling fluid; and controlling a flowrate of the drilling fluid flowing through the drill string based on the step of monitoring.

2. The method of Claim 1, wherein controlling a flowrate of the drilling fluid comprises diverting a portion of the drilling fluid from within the drill string.

3. The method of Claim 2, wherein the portion of the drilling fluid is diverted from the drill string at a bypass location that is upstream of a bottom hole assembly, wherein a bypass flow is formed by the step of diverting, wherein a flowrate of the bypass flow is adjusted so that a flowrate of drilling fluid flowing between the bypass location and bottom hole assembly is substantially equal to a designated flowrate, and wherein the bypass flow flowrate is controlled by actuating a valve in the bypass sub.

4. The method of Claim 1 , further comprising rotating a drill bit on a lower end of the drill string to excavate the wellbore to a greater depth within a surrounding formation, pressurizing the drilling fluid, and injecting the drilling fluid into an upper end of the drill string so that drilling fluid exiting the drill bit carries cuttings uphole that are formed by excavating the formation.

5. The method of Claim 1, wherein a turbine is disposed in a path of the drilling fluid flowing in the drill string and wherein the step of monitoring a flowrate of the drilling fluid comprises sensing a rotation of the turbine, the method further comprising generating electricity from the rotation of the turbine.

6. The method of Claim 1, wherein a flowrate of the bypass flow remains substantially constant during a time period when pressure in the drilling fluid changes.

7. The method of Claim 1, further comprising creating telemetry pulses with the bypass flow.

8. A drilling system comprising:-15-IM-#10838087.2a drill string in a wellbore; and a bypass sub in the drill string that, in response to a flowrate of drilling fluid sensed in the drill string, controls an amount of drilling fluid flowing through the drill string.

9. The drilling system of Claim 8, wherein the bypass sub is selectively configured between a bypass mode and a flowthrough mode, wherein when in the bypass mode a portion of a drilling fluid flowing inside the drilling string is diverted to outside of the drill string and when in the flowthrough mode the flowrates of drilling fluid upstream and downstream of the bypass sub are equal.

10. The drilling system of Claim 9, further comprising a bypass valve in the bypass sub, the bypass valve comprising an annular valve body having a downstream end and an annular valve plug having an upstream end that registers with the valve body downstream end when the bypass sub is in the flowthrough mode.

11. The drilling system of Claim 10, wherein the valve body and valve plug are selectively moveable away from one another to move the upstream and downstream ends out of registration and define an opening in the bypass valve, the drilling system further comprising a bypass port formed radially through a sidewall of the bypass sub, wherein the bypass port is in communication with drilling fluid flowing through the drill string across the opening in the bypass valve.

12. The drilling system of Claim 11, further comprising a flow controller configured to adjust relative movement between the valve body and valve plug based on a flowrate of drilling fluid sensed in the drill string at a location selected from the group consisting of upstream of the bypass sub and downstream of the bypass sub and a flow sensor in the drill string that is in communication with the flow controller and an actuator in the drill string coupled to one of the valve body or valve plug so that relative movement occurs between the valve body and valve plug by energizing the actuator.

13. The drilling system of Claim 12, wherein the actuator is a linear drive motor and an elongated rod connects the linear drive motor to a downstream end of the valve plug, and wherein a valve exit is formed through a sidewall of the valve plug adjacent to where the rod connects to the downstream end.-16-IM-#10838087.

214. The drilling system of Claim 14, wherein the flow sensor in the drill string is configured to detect a flow variation pattern of the drilling fluid flowing through the drill string, and wherein the flow variation pattern used to adjust operating parameters or operating modes of the bypass sub.

15. A drilling system comprising: a drill string in a wellbore; and a bypass sub in the drill string that, in response to a pressure of drilling fluid sensed in the annulus between the drill string and the wellbore, controls an amount of drilling fluid flowing through the drill string.-17-IM-#10838087.2

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